Contact Energy - CEN Chart [Archive] - Page 10

Snoopy

20-08-2022, 10:21 AM

The percentage to which a dividend is imputed makes a great difference to the 'gross yield' on any share. The gentailers are a particular risk here, because their dividends are based on free cashflow, which includes earnings (fully imputed) as well as some depreciation allowance that will not need to be reinvested (not imputed). What does this picture look like over the last four years? I choose four years based on the statement that dividend payments will now be based on operating cashflows from the previous four years (NZX Release 15/02/2021).

I thought about what would be the best way to calculate the average imputation rate. Each dividend would have been individually considered by the board, and a decision made on what the appropriate imputation rate should be at each dividend payment time. So I have decided to just average the raw figures, exactly as they were presented to shareholders at the time. An alternative method, that I have chosen not to use, would be to take a weighted average imputation rate attached to each dividend in proportion to the size of that dividend.

For Contact Energy, the financial year runs from 1st July to 30th June.

Dividend Payment DateAmountDividend Imputed to... {A}Legal Imputed Maximum (B)Dividend Imputation Rate (A)/(B)

18-09-2018
19cps28.00%28%100.0%

09-04-2019
16cps19.55%28%69.8%

17-09-2019
23cps20.23%28%72.3%

07-04-2020
16cps19.55%28%69.8%

15-09-2020
23cps20.23%28%72.3%

30-03-2021
14cps20.00%28%71.4%

15-09-2021
21cps21.00%28%75.0%

30-03-2022
14cps22.00%28%78.6%

Average
76.15%

Readers may notice that the imputation rate has picked up a bit over the last couple of years. However, this is logical when viewed in the big picture of a largely static profit and cashflow market (new capital raising for the new Tauhara geothermal station excepted) combined with a small reduction in the dividend. The more of the dividend that is paid from actual profits, the higher the dividend imputation rate. If you reduce your dividend in a flat earnings environment, then you are reducing that part of the dividend that does not come from profits. That means overall, the imputation rate of any such dividend paid is likely to go up.

Contact's stated new policy of reducing their dividend to 80-100% of operating free cashflow means the higher imputation rates of FY2022 are more likely to continue into the future.

The percentage to which a dividend is imputed makes a great difference to the 'gross yield' on any share. The gentailers are a particular risk here, because their dividends are based on free cashflow, which includes earnings (fully imputed) as well as some depreciation allowance that will not need to be reinvested (plus and amount not imputed). What does this picture look like over the last four years? I choose four years based on the statement that Contact dividend payments will now be based on operating cashflows from the previous four years (NZX Release 15/02/2021).

I think I have made a mistake in ancestor posts, where my previous quest to determine the 'dividend imputation rate' and use that number. Instead my objective should have been to answer the question:

"If a dividend is delivered with less than full imputation, then what divisor do I need to divide into that dividend to produce the gross dividend figure?"

So I think it is best if I move away from the concept of 'rate of dividend imputation', because that concept as you can see in my post 2251, can be ambiguous.

The last dividend in my table below has not been paid yet. But note B3 from AR2022 tells us it will be 21c '90% imputed'. If I use Doug's definition of imputation (post 2251) then this implies imputation credits per 21c share dividend of:

0.9 x 8.166667c = 7.35c

So the gross dividend becomes: 21c+7.35c = 28.35c. To get that figure from 21c requires a divisor of:

21/28.35= 0.7407

I thought about what would be the best way to calculate an 'average divisor rate' across four years. Each dividend would have been individually considered by the board, and a decision made on what the appropriate imputation rate should be at each dividend payment time. So I have decided to just average the raw figures, exactly as they were presented to shareholders at the time. An alternative method, that I have chosen not to use, would be to take a weighted average imputation rate attached to each dividend in proportion to the size of that dividend.

For Contact Energy, the financial year runs from 1st July to 30th June.

Dividend Payment DateAmountDividend Imputed to... {A}Legal Imputed Maximum (B)Net Dividend Divisor (1-A)

09-04-2019
16cps19.55%28%0.8045

17-09-2019
23cps20.23%28%0.7977

07-04-2020
16cps19.55%28%0.8045

15-09-2020
23cps20.23%28%0.7977

30-03-2021
14cps20.00%28%0.8000

15-09-2021
21cps21.00%28%0.7900

30-03-2022
14cps22.00%28%0.7800

27-09-2022
21cps25.20%28%0.7407

Average
0.7894

Readers may notice that the imputation rate has picked up a bit over the last couple of years. However, this is logical when viewed in the big picture of a largely static profit and cashflow market (new capital raising for the new Tauhara geothermal station excepted) combined with a small reduction in the dividend. The more of the dividend that is paid from actual profits, the higher the dividend imputation rate. If you reduce your dividend in a flat earnings environment, then you are reducing that part of the dividend that does not come from profits. That means overall, the imputation rate of any such dividend paid is likely to go up.

Contact's stated new policy of reducing their dividend to 80-100% of operating free cashflow means the higher imputation rates of FY2022 are more likely to continue into the future.

SNOOPY

Snoopy

20-08-2022, 12:19 PM

Contact with their '80%-100% of Free Operating Cashflow' looks, in practice, to be paying dividends towards the bottom of their indicated range. I believe this is because the policy was based on 'averaged hydro-logical conditions'. If the inflows were above average (which they were in FY2019), then the dividend was not increased. My modelled future dividend scenario is that dividends will be capped at 37cps (This reflects the period after Tauhara has been commissioned remember). Over FY2022 dividends paid during that period amounted to 35cps.

I continue to use my model based on just the last four years of operations.

1/ The 'Scenario 'Dividend Per Share' and 'Scenario Earnings Per Share' columns (from my post 2198) represent a prediction of an ongoing dividend of 80% of free cash flow being paid into the foreseeable future, but now capped at 37cps.

The FY2021 actual dividend payment, under the same policy of paying out 80-100% of free cashflow, was 35cps. This is somewhat less than my four forecast scenarios where dividends are 37cps. But these scenarios reflect a future where Tauhara is operational which should provide an incremental boost to Contact's profitability. I do not consider the modelled dividend payout to be unrepresentatively high, once Tauhara is up and running.

2/ The (A) - (B) difference column, if negative, represents the amount of the projected dividend not covered by imputation credits. This is important, because a dividend paid without imputation credits is -in accounting terms-, equivalent to giving shareholders their own capital back (equal to the amount of the unimputed dividend) complete with a tax bill. This is generally bad for investors. It is necessary to make a negative adjustment to account for any expected tax to be paid on the unimputed dividend component (Column (D).
3/ The capital component of the dividend (Column C) is the portion of shareholder equity being returned to shareholders. This will need to be removed from the dividend return calculation. Because to pay it is to return to shareholders money on the balance sheet that they already have, so it isn't a shareholder benefit.
4/ The unimputed component tax bill (Column D), represents the income tax charged on share capital that is expected to be paid by the shareholder. A 28% tax bill from the value calculated in Column C is assumed. Note that if the (A)-(B) difference were to be positive then there would be no extra tax bill. That's because in such a year, the dividend would be 'fully imputed'.
5/ The final 'Difference Column' represents the 'effective' net dividend per share, adjusted for any extra tax obligation from paying tax on unimputed distributions.

Scenario Basis Financial Yeareps (A)Scenario dps (B)Difference (A)-(B)Divie Capital Component (C)Unimputed Tax Bill (D)Difference (B)-(C)-(D)

201821.8c37.0c-15.2c15.2c4.3c17.5c

201927.3c37.0c-9.7c9.7c2.7c24.6c

202021.3c37.0c-15.7c15.7c4.4c16.9c

202128.3c37.0c-8.7c8.7c2.4c25.9c

Total98.7c (E)148.0c (F)84.9c

Business Cycle Imputation Rate (E)/(F)66.69%

.

The expected average dividend per year, net of tax is therefore: 84.9 / 4 = 21.2cps (net)

Using a tax rate of 28c this is equivalent to a gross income of: 21.2cps /(1-0.28) = 29.4cps

Now we come to a critical point in this analysis - the choosing of an 'indicative interest rate' that allows us to value Contact on the basis of being an ongoing income stream.

Contact with their '80%-100% of Free Operating Cashflow' looks, in practice, to be paying dividends towards the bottom of their indicated range. I believe this is because the policy was based on 'averaged hydro-logical conditions'. If the inflows were above average (which they were in FY2019), then the dividend was not increased. My modelled future dividend scenario is that dividends will be capped at 37cps (This reflects the period after Tauhara has been commissioned remember). Over FY2022 dividends paid during that period amounted to 35cps.

I continue to use my model based on just the last four years of operations.

1/ The 'Scenario 'Dividend Per Share' and 'Scenario Earnings Per Share' columns (from my post 2245) represent a prediction of an ongoing dividend of 80% of free cash flow being paid into the foreseeable future, but now capped at 37cps.

The FY2021 and FY2022 actual dividend payments, under the same policy of paying out 80-100% of free cashflow, was 35cps. This is somewhat less than my four forecast scenarios where dividends are 37cps. But these scenarios reflect a future where Tauhara is operational which should provide an incremental boost to Contact's profitability. I do not consider the modelled dividend payout to be unrepresentatively high, once Tauhara is up and running.

2/ The (A) - (B) difference column, if negative, represents the amount of the projected dividend not covered by imputation credits. This is important, because a dividend paid without imputation credits is -in accounting terms-, equivalent to giving shareholders their own capital back (equal to the amount of the unimputed dividend) complete with a tax bill. This is generally bad for investors. It is necessary to make a negative adjustment to account for any expected tax to be paid on the unimputed dividend component (Column (D).
3/ The capital component of the dividend (Column C) is the portion of shareholder equity being returned to shareholders. This will need to be removed from the dividend return calculation. Because to pay it is to return to shareholders money on the balance sheet that they already have, so it isn't a shareholder benefit.
4/ The unimputed component tax bill (Column D), represents the income tax charged on share capital that is expected to be paid by the shareholder. A 28% tax bill from the value calculated in Column C is assumed. Note that if the (A)-(B) difference were to be positive then there would be no extra tax bill. That's because in such a year, the dividend would be 'fully imputed'.
5/ The final 'Difference Column' represents the 'effective' net dividend per share, adjusted for any extra tax obligation from paying tax on unimputed distributions.

Scenario Basis Financial Yeareps (A)Scenario dps (B)Difference (A)-(B)Divie Capital Component (C)Unimputed Tax Bill (D)Difference (B)-(C)-(D)

201927.3c37.0c-9.7c9.7c2.7c24.6c

202021.3c37.0c-15.7c15.7c4.4c16.9c

202128.2c37.0c-8.8c8.8c2.5c25.7c

202226.9c37.0c-10.1c10.1c2.8c24.1c

Total103.7c (E)148.0c (F)91.3c

Business Cycle Imputation Rate (E)/(F)70.07%

.

The expected average dividend per year, net of tax is therefore: 91.3 / 4 = 22.8cps (net)

Using a tax rate of 28c this is equivalent to a gross income of: 22.8cps /(1-0.28) = 31.7cps

Now we come to a critical point in this analysis - the choosing of an 'indicative interest rate' that allows us to value Contact on the basis of being an ongoing income stream.

SNOOPY

Snoopy

22-08-2022, 03:54 PM

The expected average dividend per year, net of tax is therefore: 91.3 / 4 = 22.8cps (net)

Using a tax rate of 28c this is equivalent to a gross income of: 22.8cps /(1-0.28) = 31.7cps

Now we come to a critical point in this analysis - the choosing of an 'indicative interest rate' that allows us to value Contact on the basis of being an ongoing income stream.

If we assume that a business cycle investment 'gross return' of 5.0% is required, then this equates to a CEN share price of no more than:

31.7c /0.05 = $6.34

So $6.34 is therefore 'fair value' on a 'whole of business cycle' dividend basis.

We need to discount from this $6.34 - by a factor - the earnings from the as yet uncompleted Tauhara geothermal power station. We need to discount these earnings back using an appropriate 'time value of money' factor. We need to remember that this discount only applies to the incremental value of the earnings from the new Tauhara project, not all of Contact's earnings. Tauhara is now expected to be operational in the second half of FY?2023 (08-02-2022 Press Release). This means it will be fully operational over FY2024. Taking an FY2022 perspective, FY2024 is two years into the future. Thus the discounting factor that I calculated back in post 2245 over 2 years -to be 0.9070- is appropriate.

EBITDAF-DA-I-T (Normalised NPAT) for the four years under consideration for use in dividend forecasting -excluding Tuahara- , (again from post 2245) were $175m, $127m, $183m and $172m. I make the four year average $164m. Tauhara is a geothermal station, and so will likely operate as base load generation, with energy output not varying much over the years. This means that over the business cycle, with an expected net profit from Tauhara of $45m (refer post 2245), Tauhara should lift Contact Energy profits by:

$45m/$164m= 27.4%

Or looked at another way, from FY2024, Tauhara will be generating electricity supplying $45m/($164m + $45m) = 21.5% of Contact Energy profits (on average), compared to 78.5% of the .profits emerging from the rest of the Contact generation portfolio.

This means I need to adjust my fair value income yield valuation for Contact Energy as follows.

(0.785)($6.34) + (0.215)($6.34)(0.9070) = $6.21

The above valuation is effectively a 'no growth' valuation, that does not take into account any rises in value of the existing underlying power generation assets above book value. Increases in the value of power generation assets above book vale are a measure of the incremental discounted value of future cashflows, which feed from higher profits from existing generation assets. These higher profits are caused by legacy generation with low operating costs selling power into an ever higher average power price market. Contact Energy chooses not to increase the value of existing generation assets on the books annually (but competitor Mercury Energy does). However, I believe that to truly reflect the growth value of the Contact Energy generation portfolio, it is necessary to do this. So 'generation asset revaluation' is the next additive part of this Contact Energy share valuation exercise.

SNOOPY

P.S.

Tauhara Discount Factor for Future Earnings (Potential Valuation Tool)

This incremental increase in NPAT should perhaps be discounted back because it will not occur for two years time, at the point where Tauhara comes on line. For future discounting of profits, I use a 5.0% discount rate, which equates to the long term Gross Yield I am prepared to accept. Looking at the estimated incremental Tauhara profit of $45m.

1/(1.05)^2 = 0.9070

$45m x 0.9070 = $41m

Snoopy

22-08-2022, 06:08 PM

My fair value income yield valuation for Contact Energy as follows.

(0.785)($6.34) + (0.215)($6.34)(0.9070) = $6.21

The above valuation is effectively a 'no growth' valuation, that does not take into account any rises in value of the existing underlying power generation assets above book value. Increases in the value of power generation assets above book vale are a measure of the incremental discounted value of future cashflows, which feed from higher profits from existing generation assets. These higher profits are caused by legacy generation with low operating costs selling power into an ever higher average power price market. Contact Energy chooses not to increase the value of existing generation assets on the books annually (but competitor Mercury Energy does). However, I believe that to truly reflect the growth value of the Contact Energy generation portfolio, it is necessary to do this. So 'generation asset revaluation' is the next additive part of this Contact Energy share valuation exercise.

Contact Energy generation assets that have a significant unbooked premium on their book value are the hydro assets at Clyde and Roxburgh. We can estimate the quantum of this from similar increases in hydro station value that were booked by competitor Mercury Energy (see post 1878). The rising value of future cashflows, that increase the relative worth of long lived legacy power generation assets is an additional 'return' - for which I have previously coined the term 'thin air capital'. That sounds ethereal, and is, to the extent that this 'capital' appears solely on the expectation of power prices rising. However, although the short term power prices at the wholesale level go up and down, long term power prices go up and up. So in practice I have never seen any of the Mercury Energy declared new 'thin air capital' on their hydro generation assets ever vanish, even if theoretically it could (This is why I like the name 'thin air capital', because it carries a juxtaposed connotation of 'fragile permanence').

The 'thin air' capital growth for Mercury hydro assets is shown below. Both Mercury and Contact operate in the same electricity market. That is why I consider the thin air capital accumulated by Mercury as an indicative factor to use for the thin air capital accumulated (but not recognised) by Contact management over that same period. Information in the table below is derived from posts 1450 and 1456 in the Mercury thread.

Mercury Energy
Reval. Hydro & Thermal Assets ($m)
Reval. Geothermal & Other Generation Assets ($m)
Reval. Wind Generation Assets ($m)
Total Revalued Generation Assets

2015
355
142
N.A.
497

2016
82
55
N.A.
137

2017
0
52
N.A.
52

2018
0
55
N.A.
55

2019[/
151
99
N.A.
250

2020
253
43
N.A.
296

2021
550
388
N.A.
938

2022
139
1
153
293

Total
1,530

That $1,530m of thin air incremental capital raised was based on a total hydro generating capacity of 1059MW (Post 1450, Mercury Thread). The total Contact Energy hydro electric generation capacity is 784MW (my post 1514). So I can determine my 'best guess' at the thin air capital accumulated by Contact Energy subsequent to the FY2014 balance date by ratio:

$1,530m x 784MW/1059MW = $1,133m

I have decided to change my asset increment valuation approach from previous years. Revalued assets, according to accounting rules attract an associated tax liability, on a deferred basis. Contact Energy are not revaluing their assets as is their policy. But if they did, they would incur such a deferred tax liability amounting to 28% of the revaluation amount, (which may never be crystallised). Nevertheless I am going to use the revaluation amount net of any deferred tax to be consistent with the accounts of competitor Mercury Energy, which does revalue assets and does follow the revaluation and deferred tax rules.

$1,133m (Asset Revaluation) = $816m (Net Asset Revaluation) + $317m (Deferred tax liability)

New Capital projects are funded by a combination of debt and equity. If we take a 54% equity ratio going forwards as 'acceptable' (see post 2205, 54% being a typical value pre the March 2021 capital raising for Tauhara), then this $816m of new 'thin air' equity could in theory fund capital projects to the tune of:

$816m / 0.54 = $1,511m

Take the project capital needed to complete Tauhara out of that total, and new incremental project capital is reduced to:

$1,511m - $818m = $693m.

Now 693/818= 0.847. And 168MW x 0.847 = 142MW

Theoretically, add in a new companion bond program, and it means I can see equity capital for another Tauhara sized field geothermal station (actually a geothermal station 84.7% the size) as being available right now.

A new 142MW power station would lift operational generating capacity by

(142MW x 0.94) / (403MW + 527MW) = +14.4%

(refer post 2206 for method)

This raises my 'fair value' of Contact Energy, based on my steady state income valuation, by 14.4%

$6.21 x 1.144 = $7.10

CEN closed on the market on Friday at $7.85, which makes it 11% overvalued by my way of looking at things.

SNOOPY

discl: holder

Snoopy

23-08-2022, 10:31 AM

FY2021Contact EnergyMercury Energy

No. Shares776.1m1,400m

Share Price (12-08-2022)$7.71$6.50

Normalised PE32.764.4

Normalised NPAT Margin8.8%8.4%

Normalised NPAT eps23.6c10.1c

Gross dps44.3c25.3c

Gross Dividend Yield5.75%3.89%

ROE (Assets at Cost)10.6%6.6%

Bank Debt$856m$1,491m

Min. Debt Repayment Time4.68 years10.5 years

Snoopy's Fair Share Price Valuation (3)$6.98$5.76

Current Market Premium or Discount to Fair Value+10.5%+12.8%

Notes:

1/ Both CEN valuation and MCY valuation contain adjustment factors to include the value of 'thin air capital' accumulated. For Mercury this is +23.0%. For Contact Energy the adjustment factor is +22.5% It is no longer Contact policy to revalue their assets annually. Hence Contact's balance sheet does not contain 'thin air capital', but Mercury's balance sheet does.

2/ The FY2021 financial statements of both companies were compiled on the assumption that the Tiwai Point Aluminium Smelter is to remain as a going concern.

3/ The working for 'Snoopy's fair price valuations may be found on this thread in posts 2199 and 2201 (Contact Energy) and on the Mercury Energy Thread (posts and 1428, 1442 and 1451). The method I used was capitalising the dividend averaged over recent years (in the case of Contact revised according to present dividend policy), and added a 'fudge factor' representing future forecast dividends from further power generation facilities planned but not yet built.

------------------------------

My snoopshot view shows a present day 'close value tussle' between 'Contact Energy' and 'Mercury Energy', notwithstanding the stratospheric PE ratios now commanded by both companies. My modelling is based on both companies building substantial new power stations (Tauhara Geothermal for Contact, Turitea Wind for Mercury), with those new incremental power station earnings already priced in to today's share market price for both. Once these developments come on stream, those historic stratospheric market PEs (which are based on historic earnings) for MCY and CEN should reduce.

Mercury Energy has in August 2021, post the FY2021 reporting period, unwound a strategic stake in 'Tilt Renewables', a listed entity that developed and operated wind farms in New Zealand and Australia. 'Tilt Renewables' has been subject to a joint takeover offer from 'Mercury Energy' and Australian based 'Powering Australian Renewables' (PowAR). The result being that Tilt was 'carved up', with Mercury acquiring the NZ based windfarm portfolio (mainly Manawatu based previously owned by Trustpower) and PowAR the Australian based windfarms.

'Net Profit margin' has tightened up between the two protagonists from the previous comparative year. Mercury noted over FY2021 particular 'headwinds that included challenging generation conditions and elevated spot prices' (AR2021 p8). The debt risk indicator of 'MDRT' now favours Contact Energy, which did a significant capital raising during the FY2021 year.

The present day Contact Energy and Mercury market price premiums are not sufficient to make me sell up. There are sufficient growth plans tabled, beyond Turitea and Tauhara, to keep each business growing. The decarbonisation program at Contact as they continue to roll out geothermal developments, and soon windfarms, combined with the winding down of their remaining gas burning assets, should lower the cost base of the power being generated. Mercury is in the middle of a major restructure with the incorporation of new central North Island both organic (Turitea) and acquired (Tilt) wind farm assets. With their strong central North Island hydro-generation presence, this combination should prove an energy supply management game changer.

I will plan to update my comparative table as both Contact and Mercury produce their full year results over the next month or so. In the meantime I will be 'sitting tight' on both my Contact Energy and Mercury Energy shareholdings.

FY2022Contact EnergyMercury Energy

No. Shares780.6m1,400m

Share Price (22-08-2022)$7.85$6.35

Normalised PE35.754.7

Normalised NPAT Margin9.3%9.1%

Normalised NPAT eps22.0c11.6c

Gross dps44.3c25.3c

Gross Dividend Yield5.64%3.89%

ROE (Assets at Cost)10.1%5.7%

Bank Debt$1,099m$2,831m

Min. Debt Repayment Time6.39 years12.0 years

Snoopy's Fair Share Price Valuation (3)$7.10$6.01

Current Market Premium or Discount to Fair Value+10.6%+5.7%

Notes:

1/ Both CEN valuation and MCY valuation contain 'adjustment factors' to include the value of 'thin air capital' accumulated. For Mercury this is +26.8%. For Contact Energy the 'adjustment factor' is +14.4% It is no longer Contact policy to revalue their assets annually. Hence Contact's balance sheet does not contain 'thin air capital', but Mercury's balance sheet does. The Contact Energy 'Thin Air Capital' used in this comparison is my own construct, based on what would have happened if Contact had followed Mercury's 'Thin Air capital' policy

2/ The FY2022 financial statements of both companies were compiled on the assumption that the Tiwai Point Aluminium Smelter is to remain as a going concern.

3/ The working for 'Snoopy's fair price valuations may be found on this thread in posts 2253, 2254 and 2255 (Contact Energy) and on the Mercury Energy Thread (posts and 1462 and 1463). The method I used was capitalising the dividend averaged over recent years (in the case of Contact revised according to present dividend policy), and added an 'adjustment factor' representing future forecast dividends from further power generation facilities planned but not yet built.

------------------------------

My financial modelling is based on both companies having already completed building substantial new power stations (Tauhara Geothermal for Contact, Turitea North Wind for Mercury), with those new incremental power station earnings already priced in to today's share market price for both. The earnings included from Tauhara are forecasts. The earnings included from Turitea North are real, but inconsistent with full year annual production, because this wind-farm was only commissioned during FY2022 (fully commissioned December 2021).

Mercury Energy in August 2021, early in the FY2022 reporting period, unwound a strategic stake in 'Tilt Renewables', a listed entity that developed and operated wind farms in New Zealand and Australia. The net result was that Tilt was 'carved up', with Mercury acquiring the NZ based windfarm portfolio (mainly Manawatu based previously owned by Trustpower). Wind generation from this acquisition was slightly below expectations with less windy weather than forecast.

Very late in the financial year (02-05-2022), Mercury acquired the retail customer base of Trustpower for $467m. Consequently the incremental debt of $187m incurred in making this purchase appeared on the balance sheet immediately. But the earnings stream from this purchase will not fully come on song until FY2023 (the Trustpower retail business contributed just $12m in revenue over FY2022). This points to a reduction in the historic stratospheric market PER for Mercury in particular over FY2023.

'Net Profit margin' has tightened up between the two protagonists from the previous comparative year. But Mercury noted over FY2022 a second year low inflows into the Waikato catchment (just the 30th percentile on average). Heavy rainfall in June 2022 restored the Lake Taupō level to well above the historic average and 70% full, positioning hydro generation well for the start of FY2023. Contact had less 'operational excuses ' to report, this years result being achieved "with highly variable hydrology" (AR2022 p9) being the main signal of an atypical year. With more normal hydro-logical conditions, it looks like Mercury will see more incremental improvement than Contact.

The debt risk indicator of 'MDRT' favours Contact Energy, which did a significant capital raising during the FY2021 year.

The significant difference in ROE is because Mercury, has dramatically increased their generation capacity by purchasing assets at 'current market prices' (the Tilt Windfarms). It is not a sign of asset management incompetence.

The present day Contact Energy and Mercury market price premiums are not sufficient to make me sell up. There are sufficient growth plans tabled, beyond Turitea and Tauhara, to keep each business growing. The decarbonisation program at Contact as they continue to roll out geothermal developments, and soon windfarms, combined with the winding down of their remaining gas burning assets, should lower the cost base of the power being generated. Mercury is in the middle of a major restructure with the incorporation of new central North Island both organic (Turitea) and acquired (Tilt) wind farm assets. With their strong central North Island hydro-generation presence, this combination should prove an energy supply management game changer. I see a bright future for both companies. But in my ever present search for value, I would wait for some kind of cyclical share price dip before topping up my existing shareholdings in either.

SNOOPY

discl: hold MCY and CEN

Snoopy

23-08-2022, 01:28 PM

I like to do these head to head comparisons using a 30th September comparison date. This for convenience (corresponding in my records to six months into the tax year) and also because it gives the market a month or so to 'digest' an annual result announced in August, normally related to a reporting period ended 30th June. In actuality I delayed my September 2021 report to early August 2022 making it way out of date. Consequently I included some updated information to make it more relevant until the FY2022 edition of my head to head report was ready.

Now I want to go back to 30-09-2021 and publish my comparison as if it had been written then. This will provide a better comparative marker with the FY2022 head to head table.

FY2021 (Retrospective)Contact EnergyMercury Energy

No. Shares776.1m1,400m

Share Price (30-09-2021)$8.45$6.50

Normalised PE35.864.4

Normalised NPAT Margin8.8%8.4%

Normalised NPAT eps23.6c10.1c

Gross dps46.4c22.5c

Gross Dividend Yield5.49%3.46%

ROE (Assets at Cost)10.6%6.6%

Bank Debt$856m$1,491m

Min. Debt Repayment Time4.68 years10.5 years

Snoopy's Fair Share Price Valuation (3)$6.98$5.76

Current Market Premium or Discount to Fair Value+21.1%+12.8%

Notes:

1/ Both CEN valuation and MCY valuation contain adjustment factors to include the value of 'thin air capital' accumulated. For Mercury this is +23.0%. For Contact Energy the adjustment factor is +22.5% It is no longer Contact policy to revalue their assets annually. Hence Contact's balance sheet does not contain 'thin air capital', but Mercury's balance sheet does.

2/ The FY2021 financial statements of both companies were compiled on the assumption that the Tiwai Point Aluminium Smelter is to remain as a going concern.

3/ The working for 'Snoopy's fair price valuations' may be found on this thread in posts 2199, 2201 and 2202 (Contact Energy) and on the Mercury Energy Thread (posts and 1428, 1442 and 1451). The method I used was capitalising the dividend averaged over recent years (in the case of Contact revised according to present dividend policy), and adding an 'adjustment factor' representing future forecast dividends from further power generation facilities planned but not yet built.

------------------------------

My snoopshot view shows a clear value benefit in holding 'Mercury Energy' over 'Contact Energy'. Since I am 'posting from the future', as far as this valuation study goes, we can see that the MCY share price held steady over the year while the CEN share price declined by 10%. I will take that as some vindication of my valuation methodology. The high PE ratios now commanded by both companies is both a positive cashflow issue (dividends are a lot higher than profits), and representative of the fact that both companies are in a 'development phase'. .

My modelling is based on both companies building substantial new power stations (Tauhara Geothermal for Contact, Turitea Wind for Mercury), with those new incremental power station earnings already priced in to today's share market price for both. Once these developments come on stream, those historic stratospheric market PEs (which are based on historic earnings) for MCY and CEN should reduce.

Mercury Energy has in August 2021, post the FY2021 reporting period, unwound a strategic stake in 'Tilt Renewables', a listed entity that developed and operated wind farms in New Zealand and Australia. 'Tilt Renewables' has been subject to a joint takeover offer from 'Mercury Energy' and Australian based 'Powering Australian Renewables' (PowAR). The result being that Tilt was 'carved up', with Mercury acquiring the NZ based windfarm portfolio (mainly Manawatu based previously owned by Trustpower), while PowAR acquired the Australian based windfarms.

'Net Profit margin' has tightened up between the two protagonists from the previous comparative year. Mercury noted over FY2021 particular 'headwinds that included challenging generation conditions and elevated spot prices' (AR2021 p8). The debt risk indicator of 'MDRT' now favours Contact Energy, which did a significant capital raising during the FY2021 year.

The historic Contact Energy and Mercury market price premiums were not sufficient to make me sell up. There are sufficient growth plans tabled, beyond Turitea (Mercury) and Tauhara (Contact), to keep each business growing. The decarbonisation program at Contact as they continue to roll out geothermal developments, and soon windfarms, combined with the winding down of their remaining gas burning assets, should lower the cost base of the power being generated. Mercury is in the middle of a major restructure with the incorporation of new central North Island both organic (Turitea) and acquired (Tilt) wind farm assets. With their complimentary strong central North Island hydro-generation presence, the Wind / 'Hydro battery' combination should prove an energy supply management winner.

SNOOPY

Jantar

23-08-2022, 02:14 PM

….

But where did the water from Lake Roxburgh come from? It came upstream from the Clyde dam. And it would only benefit Contact to release extra water from the Clyde dam for Lake Roxburgh (and hence Onslow) when power prices are high.

b/ If the Clyde dam was forced to release water to fill Lake Roxburgh when prices were low (Prof Beardsly's scenario), then doesn't that mean that water will be running through the Clyde dam when prices are low? That surely is not what Contact Energy wants?.....
SNOOPY
Both Clyde and Roxburgh are run-of river stations and both have minimum flow requirements. For Clyde it is 120 cumecs from 1 hr after sunset to 1 hr before sunrise, measured at the Clyde Golf Course which is about 1 1/4 hours flow time down stream from Clyde. For Roxburgh it is 250 cumecs measured immediately below Roxburgh power station. Thus Contact has to release water from Clyde to supply Roxburgh whether prices are high or low, and Clyde cannot hold water back over the 250 cumecs needed at Roxburgh for more than a few hours or it will exceed the maximum operating level of Clyde dam. Total storage in Clyde is measured in hours, not days, and Roxburgh only has 6 hours storage. Also to put the flows in perspective, a single machine at Roxburgh uses 100 cumecs at full load. Depending on whether Onslow uses the 120 MW units as suggested by Majeed, or the 250 MW units suggested by MBIE, the flow of an Onslow unit on full load would be either 17 or 40 cumecs. So a very small flow to or from Onslow compared to Roxburgh's flow.

If the Onslow intake is above the Roxburgh dam, Contact loses a small amount of water when flows re high and prices are low, but gets it all back (with no losses) when flows are low and prices are high. If the intake is below Roxburgh, then a new dam would need to built across the Clutha River in order to give a lower reservoir and sufficient pumping head. This in turn would be detrimental to Contact as it would raise the Roxburgh tail water level and reduce the operating head, and efficiency, of the Roxburgh turbines.

When the Clutha River flows are low enough that water is being released from Hawea to meet those requirements power prices are high enough that Onslow would be generating, and thus assisting Roxburgh to meet its minimum flow and reducing the amount of water that has to be wasted from Hawea. This allows the Hawea water to used more efficiently at both Clyde and Roxburgh.

Pumping would only occur when prices are low, or when there is more water in the Clutha river than is needed for minimum flows in the Clutha.

Jantar

23-08-2022, 02:16 PM

Government policy is that nobody owns water. Therefore water can be taken to fill Lake Onslow by whoever, whenever. If Contact wanted an unwinable battle, they could hold water at Clyde, and when Lake Roxborough hit minimum level, Lake Onslow could be filled no further. Then legislation would be enacted to force the release of water

But it won't come to that. The generators know they have 10 years of massive profits left. Then it will be a different market, different CEO, different BOD etc and probably a different wholesale pricing mechanism

The minimum flow from Roxburgh requires that water be released from Clyde. Similarly, water cannot be held back at Clyde as Clyde's storage is measured in hours, not days.

Jantar

23-08-2022, 02:21 PM

…..
a/ The power price fluctuates with time AND SO
b/ It becomes possible to take power from a generation site- where there is no alternative use of that power at that time (i.e. it has a low instantaneous 'market value') - so that you can use what would otherwise be 'wasted energy' to 'pump water up hill'.

The problem I see with using hydro-electricity to do this is that there is always an alternative use. Just keep the water behind the dam until it is needed! …...
SNOOPY
Clyde dam has 22 hours storage at average inflows and minimum outflows, so cannot simply hold water behind the dam until it is needed.

RTM

24-08-2022, 04:05 PM

https://www.msn.com/en-nz/news/national/impact-of-contact-energy-s-clyde-dam-on-kawarau-arm-of-lake-dunstan-to-be-reviewed/ar-AA111sJJ?ocid=msedgntp&cvid=5b6a28a56d7f4dff9014b67d88a9f1f9

FYI

xafalcon

25-08-2022, 07:36 AM

Both Clyde and Roxburgh are run-of river stations and both have minimum flow requirements. For Clyde it is 120 cumecs from 1 hr after sunset to 1 hr before sunrise, measured at the Clyde Golf Course which is about 1 1/4 hours flow time down stream from Clyde. For Roxburgh it is 250 cumecs measured immediately below Roxburgh power station. Thus Contact has to release water from Clyde to supply Roxburgh whether prices are high or low, and Clyde cannot hold water back over the 250 cumecs needed at Roxburgh for more than a few hours or it will exceed the maximum operating level of Clyde dam. Total storage in Clyde is measured in hours, not days, and Roxburgh only has 6 hours storage. Also to put the flows in perspective, a single machine at Roxburgh uses 100 cumecs at full load. Depending on whether Onslow uses the 120 MW units as suggested by Majeed, or the 250 MW units suggested by MBIE, the flow of an Onslow unit on full load would be either 17 or 40 cumecs. So a very small flow to or from Onslow compared to Roxburgh's flow.

If the Onslow intake is above the Roxburgh dam, Contact loses a small amount of water when flows re high and prices are low, but gets it all back (with no losses) when flows are low and prices are high. If the intake is below Roxburgh, then a new dam would need to built across the Clutha River in order to give a lower reservoir and sufficient pumping head. This in turn would be detrimental to Contact as it would raise the Roxburgh tail water level and reduce the operating head, and efficiency, of the Roxburgh turbines.

When the Clutha River flows are low enough that water is being released from Hawea to meet those requirements power prices are high enough that Onslow would be generating, and thus assisting Roxburgh to meet its minimum flow and reducing the amount of water that has to be wasted from Hawea. This allows the Hawea water to used more efficiently at both Clyde and Roxburgh.

Pumping would only occur when prices are low, or when there is more water in the Clutha river than is needed for minimum flows in the Clutha.

Great summary. Thanks for taking the time to explain

Snoopy

25-08-2022, 09:38 PM

I have been trying to keep my two comparative CEN vs MRP posts from an FY2022 perspective (post 2256) and an FY2021 perspective (post 2257) as 'fact based'. In this post I am throwing in some of my own opinions.

The NZ gentailers look to have been forgiven a lot, as interest rates fell as a result of the Covid-19 'interest rate reset', and there was a mad scramble for yield. That 'mad' became more than a euphemism when a Blackrock ESG fund put Meridian and Contact Energy in a concentrated ESG fund, using sustainability as a share selection criteria. That saw the Meridian share price peak at just shy of $10, while Contact was just shy of $11. With customer cash inflows, the Blackrock fund was forced to buy these two shares at 'whatever the cost' - true madness.

By contrast, Mercury Energy did not scale the same crazy heights, topping out at about $7.25, and Mercury is still within strike of this all time peak today. Mercury never made it into the Blackrock ESG fund, which is why it largely escaped the mania. Mercury also has a much better growth record than MEL and CEN, as evidenced by the fact that it has largely swallowed what was the old 'fifth player' Trustpower (hydro generation and industrial customers excepted).

Nevertheless the gentailers have not lost their 'darling status' with the brokers. At the end of the FY2022 annual result presentation one Jarden broker got very excited about the improved cashflow that was to come from Contact's new Tauhara generation plant. Jarden issued a buy upgrade the next day on the assumption that all of that improved cashflow would go straight through to the dividend. However CEO Mike Fuge specifically said that forecasting a dividend two or three years out was not company policy. The big 'Geofutures' Wairakei field redevelopment, coming on stream when the original 60 year Wairakei old generation plant is due to be retired, will no doubt require a lot of that 'spare' cash, as will cost inflation in construction. Plus we have a very competitive electricity market, which means that some of those forecast revenue efficiency gains will not all make their way to the bottom line as that Jarden analyst believes.

I don't wish to single out Jarden's here as, from what I have read, other brokers think along similar lines: Looking for that positive cashflow 'hit', even when the CEO of the company concerned warns that it may not eventuate. In turbulent times, people will always need power. So the Gentailers have become untouchable rocks in any income generating share portfolio. 'Minor' considerations, like the mechanics of operating in a capital intensive competitive market, no longer require any consideration from some analysts, or so it would seem.

For this reason I believe that Mercury, in particular, is underrated by many retail focussed brokers, simply because it has the lowest dividend yield of the gentailers, (albeit the only dividend fully imputed). Certainly compared with Contact Energy, that debt position at Mercury is a concern, with MDRT blowing out from a high 10.5years a year ago to an even higher 12 years now. The bidding war for Tilt Renewables meant that Mercury did overpay for their newly acquired NZ wind farm assets. But they are also the only bidder that could afford to overpay, because of the central North Island power generating synergies available to them. With Mercury, we furthermore also have to remember that the full burden of the debt required to buy the Trustpower retail customers is on the balance sheet. But the full earning capacity of those acquired customers is not yet in the income statement.

A factor that favours Contact relative to Mercury is the higher gross income yield on the dividend payments, despite dividends not being fully imputed at Contact. However, when you consider that the imputed income credits attached at Contact seem to regularly exceed the declared profit tax bill, I am puzzled. My best explanation is that there is a bank of imputation credits that falls outside declared income, and this has been used to 'super-impute' many Contact Energy dividends. This balance, if it exists, must be finite and I have had a go at explaining it in post 1819. This means we might expect to see the imputation percentage of dividends from Contact Energy to reduce in future years, lowering the gross dividend yield for Contact in the future accordingly (IOW the underlying gross yield for Contact Energy is overstated on the CEN vs MCY comparison chart).

Given that Mercury had a less that optimal hydrological inflows over FY2022 (and FY2021 in fact), I believe the current market valuations for CEN and MCY are focussed more on current earnings, than the big multi-year picture. For the record, I don't believe the complimentary nature of the central North Island wind and water assets - in more normal hydrological conditions- are reflected in that MCY share price today. So despite what the brokers think, I am going for Mercury Energy as the better buy at today's price levels, with Contact Energy a close but honorable second. Don't get the idea that either is a 'get rich quick scheme' though!

SNOOPY

silu

26-08-2022, 11:02 AM

Snoopy

26-08-2022, 11:24 AM

Both Clyde and Roxburgh are run-of river stations and both have minimum flow requirements. Total storage in Clyde is measured in hours, not days.

I have to admit I was not 100% sure what the definition of a 'run of the river' hydropower station was. From Wikipedia:
https://en.wikipedia.org/wiki/Run-of-the-river_hydroelectricity

"The use of the term "run-of-the-river" for power projects varies around the world. Some may consider a project run-of-the-river if power is produced with no water storage, but limited storage is considered run-of-the-river by others. Developers may mislabel a project run-of-the-river to soothe public perception about its environmental or social effects. The European Network of Transmission System Operators for Electricity distinguishes run-of-the-river and pondage hydropower plants, which can hold enough water to allow generation for up to 24 hours (reservoir capacity / generating capacity ≤ 24 hours), from reservoir hydropower plants, which hold for more than 24 hours of generation without pumps."

I think what was confusing me is that, having seen the Clyde dam, which ended up being the most expensive and drawn out civil engineering constriction project in New Zealand up until that time (and likely since), I had trouble reconciling this with holding such a 'small' amount of water. Technically Lake Dunstan, according to the European Network of Transmission System Operators, would be classified as a 'pond'. I guess this classification truly highlights the tremendous volume of natural water flow that comes down the Clutha River.

For Clyde the minimum flow requirement is 120 cumecs from 1 hr after sunset to 1 hr before sunrise, measured at the Clyde Golf Course which is about 1 1/4 hours flow time down stream from Clyde. For Roxburgh it is 250 cumecs measured immediately below Roxburgh power station. Thus Contact has to release water from Clyde to supply Roxburgh whether prices are high or low, and Clyde cannot hold water back over the 250 cumecs needed at Roxburgh for more than a few hours, or it will exceed the maximum operating level of Clyde dam. Total storage in Clyde is measured in hours, not days, and Roxburgh only has 6 hours storage.

I take it from this that what you are saying Jantar is that if you were to 'siphon off' water from the Clutha for Onslow, this would have to be done based very much on current prevailing weather front patterms, while still factoring in the snow-melt inflows that should be more predictable. 'Planning' to top up Onslow during a certain season, and at that time only, would not be possible? The performance of the two Clutha hydro dam system is determined by what is happening with the dam with the largest minimum flow requirement (Roxburgh), which happens to have the smaller 'pond' supplying it as well (Lake Roxburgh).

From what you have told us, if I were managing the system, I would run the Clyde dam at the minimum allowable flow rate of 120cumecs over night to co-incide with minimum power demand (say for eight hours). Then I would open the turbine gates up at Clyde during the day to an 'accumulated energy total flow' of 'F' (for the remaining 16 hours in one day) to ensure that Roxburgh received its daily dose of 250cumecs over 24 hours.

Clyde daily flow = 16F + 8(120cumecs) = 24(250cumecs) = Roxburgh daily flow => F= [24x250-8x120]cumecs/16 = 5040cumecs

Calculate Flow Rate: 5040/16= 315 cumecs/hour at Clyde 'during the day' (minimum flow rate).

Also to put the flows in perspective, a single machine at Roxburgh uses 100 cumecs at full load. Depending on whether Onslow uses the 120 MW units as suggested by Majeed, or the 250 MW units suggested by MBIE, the flow of an Onslow unit on full load would be either 17 or 40 cumecs. So a very small flow to or from Onslow compared to Roxburgh's flow.

If the Onslow intake is above the Roxburgh dam, Contact loses a small amount of water when flows re high and prices are low, but gets it all back (with no losses) when flows are low and prices are high.

Let's unpack this first option first. If the flow is taken from above Roxburgh to feed Onslow, then surely the flow through Roxburgh doesn't come into consideration. The extra flow to supply Onslow must come upstream from Clyde, not Roxburgh! 40cumecs over and above the minimum 120cumecs Clyde night time minimum is a 33% increase in flow from Clyde, and represents 33% more power than required being produced overnight from Clyde (just when they don't want to produce it). Looked at another way, that hydro-energy, if kept in the Clyde dam overnight, could otherwise have been fed into the electricity grid when prices are higher during the next day. This option is 'bad news' for Contact Energy, the way I read it.

If the intake is below Roxburgh, then a new dam would need to built across the Clutha River in order to give a lower reservoir and sufficient pumping head. This in turn would be detrimental to Contact as it would raise the Roxburgh tail water level and reduce the operating head, and efficiency, of the Roxburgh turbines.

Yes, quite right. But how high would that new dam downstream of Roxburgh have to be? I guess it depends on the capacity of the pumping system, pumping the water uphill to Onslow. I am picking the capacity of that pump would be a lot less than the water flow rate flowing through a turbine downhill from from Onslow when the nationwide power supply is short. So you might need quite a substantial dam downstream of Roxburgh. That sounds like really bad news for Contact, because the discharge head level from Roxburgh would in effect be permanently raised. And that would effect power generation from Roxburgh 24/7.

In summary, neither of these two 'Onslow options' seem very palatable for Contact shareholders.

Pumping would only occur when prices are low, or when there is more water in the Clutha river than is needed for minimum flows in the Clutha.

But didn't you just tell us that Roxburgh and Clyde only have a storage capacity of a few hours? How can you then say that pumping will occur only when power prices are low (in fact four quoted paragraphs back, you said 'high or low', which I have highlighted in bold)?

SNOOPY

Jantar

26-08-2022, 03:23 PM

I have to admit I was not 100% sure what the definition of a 'run of the river' hydropower station was. From Wikipedia:
https://en.wikipedia.org/wiki/Run-of-the-river_hydroelectricity

"The use of the term "run-of-the-river" for power projects varies around the world. Some may consider a project run-of-the-river if power is produced with no water storage, but limited storage is considered run-of-the-river by others. Developers may mislabel a project run-of-the-river to soothe public perception about its environmental or social effects. The European Network of Transmission System Operators for Electricity distinguishes run-of-the-river and pondage hydropower plants, which can hold enough water to allow generation for up to 24 hours (reservoir capacity / generating capacity ≤ 24 hours), from reservoir hydropower plants, which hold for more than 24 hours of generation without pumps."

I think what was confusing me is that, having seen the Clyde dam, which ended up being the most expensive and drawn out civil engineering constriction project in New Zealand up until that time (and likely since), I had trouble reconciling this with holding such a 'small' amount of water. Technically Lake Dunstan, according to the European Network of Transmission System Operators, would be classified as a 'pond'. I guess this classification truly highlights the tremendous volume of natural water flow that comes down the Clutha River.

I take it from this that what you are saying Jantar is that if you were to 'siphon off' water from the Clutha for Onslow, this would have to be done based very much on current prevailing weather front patterms, while still factoring in the snow-melt inflows that should be more predictable. 'Planning' to top up Onslow during a certain season, and at that time only, would not be possible? The performance of the two Clutha hydro dam system is determined by what is happening with the dam with the largest minimum flow requirement (Roxburgh), which happens to have the smaller 'pond' supplying it as well (Lake Roxburgh).

From what you have told us, if I were managing the system, I would run the Clyde dam at the minimum allowable flow rate of 120cumecs over night to co-incide with minimum power demand (say for eight hours). Then I would open the turbine gates up at Clyde during the day to an 'accumulated energy total flow' of 'F' (for the remaining 16 hours in one day) to ensure that Roxburgh received its daily dose of 250cumecs over 24 hours.

Clyde daily flow = 16F + 8(120cumecs) = 24(250cumecs) = Roxburgh daily flow => F= [24x250-8x120]cumecs/16 = 5040cumecs

Calculate Flow Rate: 5040/16= 315 cumecs/hour at Clyde 'during the day' (minimum flow rate).

Let's unpack this first option first. If the flow is taken from above Roxburgh to feed Onslow, then surely the flow through Roxburgh doesn't come into consideration. The extra flow to supply Onslow must come upstream from Clyde, not Roxburgh! 40cumecs over and above the minimum 120cumecs Clyde night time minimum is a 33% increase in flow from Clyde, and represents 33% more power than required being produced overnight from Clyde (just when they don't want to produce it). Looked at another way, that hydro-energy, if kept in the Clyde dam overnight, could otherwise have been fed into the electricity grid when prices are higher during the next day. This option is 'bad news' for Contact Energy, the way I read it.

Yes, quite right. But how high would that new dam downstream of Roxburgh have to be? I guess it depends on the capacity of the pumping system, pumping the water uphill to Onslow. I am picking the capacity of that pump would be a lot less than the water flow rate flowing through a turbine downhill from from Onslow when the nationwide power supply is short. So you might need quite a substantial dam downstream of Roxburgh. That sounds like really bad news for Contact, because the discharge head level from Roxburgh would in effect be permanently raised. And that would effect power generation from Roxburgh 24/7.

In summary, neither of these two 'Onslow options' seem very palatable for Contact shareholders.

But didn't you just tell us that Roxburgh and Clyde only have a storage capacity of a few hours? How can you then say that pumping will occur only when power prices are low (in fact four quoted paragraphs back, you said 'high or low', which I have highlighted in bold)?

SNOOPY
That is a long response, but I still don't believe you understand the situation.

First, Onslow would not pump, or generate, based on the season, but rather it would do so based on the wholesale price. It is likely that it would be pumping when prices are less than around $50 per MW, and generating when prices are above $100 per MW. Because it can bid (for pumping) and offer (for generation) there would be a number of price bands, not a single price in each direction. It is likely that it would do both: Pumping overnight when prices are low, and generating during the day when prices are high on many days.

Second: The minimum flows are just that, minimum, yet the actual flow through the machines is constantly varying according to dispatch and small variations in frequency. To ensure that the minimum flow is not breached Roxburgh would normally have a minimum offer of 120 MW which is the most efficient load on 3 machines, and gives an outflow of 286 cumecs. The 120 cumec minimum flow is less than can be dispatched on a single machine, but allows for the timing issue of the flow station being 1 1/4 hours flow time downstream while the offer and dispatch process is in half hour increments.

Third: Clutha is a run of River scheme as the storage available at Clyde and Roxburgh is less than can be held for a single day. The median natural inflow at Clyde is 515 cumecs plus any water released from Hawea. If there are median inflows, and minimum water being released from Hawea, and only releasing sufficient water from Clyde to meet the 286 cumecs from Roxburgh, and Lake Dustan level was in the lower 1/4 of its 1 m operating range prior to starting, Clyde would be spilling water within 18 to 22 hours. This is the main definition of Run-of -River: Water reaching the top dam must be passed through within 24 hours.

Fourth: All hydro generators have an efficiency curve, and a flow point per machine where they are most efficient. A single machine at Clyde at 108 MW uses only 1.83 cumecs per MW, but at its minimum load of 70 MW uses 2.03 cumecs per MW. At Roxbugh the range is from 2.43 cumecs per MW at the most efficient point to 2.81 cumecs per MW at the least efficient point. That water saving per MW is a huge incentive to always load machines in most efficient manner possible, and is another reason why minimum flows are seldom targeted.

Clyde is able to shut down for a few hours overnight when flows are low, and doesn't have to supply water to Roxburgh continuously as Roxburgh has around 6 hours of storage.

NZ's power prices are closely linked to inflows, not storage as many seem to believe. When flows are low, as per your calculations in your second paragraph, prices would be high, and Onslow would be generating, not pumping. Thus overnight pumping at Onslow would only occur when there was above median flows in the river. In your final paragraph I think you are confusing the release of water to ensure minimum flows are being maintained Irrespective of price, and pumping for Onslow which would only occur when natural flows are above median and prices are low. If Onslow is generating during times of higher price and lower flows then Clyde would not need to release as much water for Roxburgh as Onslow would be supplying some should the Onslow scheme be above Roxburgh.

If the site selected is blow Roxburgh then the water height for pumping needs to 2.5 times the diameter of the intake pipe.

Snoopy

26-08-2022, 08:00 PM

To re-orientate where I am going with my posting, I am interested in what threat an Onslow pumped hydro scheme installed on the Clutha River will have on the profitability of Contact Energy.

Rather than re-quote Jantar's useful technical background posts, I have rearranged the information he has supplied us in the table below. The order of discharge from 'mountains to the sea' along the Clutha is: Hawea (Genesis Energy Owned), Clyde (Contact), Onslow (Goverment owned) and Roxburgh (Contact).

I don't think there is any doubt that an alternative siting of the feed and discharge of Onslow downstream of Roxburgh would be the worst of the two proposed plans outcome for Contact. That option would require the construction of a whole new dam, below Roxburgh. That in turn would lower the discharge head of Roxburgh - permanently. And that would mean a permanent reduction in the power generating capability of the Roxburgh dam station. Fortunately for Contact shareholders, with a whole extra dam required, this looks likely to be an expensive option. So I am going to concentrate on the cheaper option of installing the 'pumping up' and 'discharge down' capacity of Onslow, by plugging it into the Clutha water flow between Clyde and Roxburgh.

Onslow, Roxburgh and Clyde on the Clutha

Median Inflow
Power Station
Storage at Maximum Output
Desired Minimum Power Generated (for efficiency)
Water Discharge Minimum (for efficiency)
Lowest Power Generated
Lowest Water Discharge
Legal Minimum Discharge

515cumecs/s
Clyde dam (4x108MW=432MW)
10 hours
108MW
198cumecs/s
70MW
142cumecs/s
120cumecs/s

Onslow (4x250MW=1000MW)
'A lot'
250MW
40cumecs/s

Roxburgh dam (8x40MW=320MW)
6 hours
120MW
286cumecs/s
80MW
215cumecs/s
250cumecs/s

Notes

1/ Median inflow into system can be supplemented by opening the upstream gates at Lake Hawea.
2/ The higher head that the water falls through, releasing more potential energy per unit of water, is the reason for the more 'efficient' generation at Onslow (for a given amount of water through the turbines).
3/ Power station information for Onslow represents one option being considered and may not be the final option chosen, should Onslow go ahead.

NZ's power prices are closely linked to inflows, not storage as many seem to believe. When flows are low, prices would be high, and Onslow would be generating, not pumping. Thus overnight pumping at Onslow would only occur when there was above median flows in the river. I think you are confusing the release of water to ensure minimum flows are being maintained Irrespective of price, and pumping for Onslow which would only occur when natural flows are above median and prices are low.

My understanding of the rationale for Onslow is for it to be government controlled 'reserve generation' that puts a lid on the maximum price offered into the nationwide power system. Without Onslow, this maximum price would be controlled by the gentailers who have made big money from rogue power price peaks. Peaking Thermal generation in particular would not be competitive with Onslow. But if Onslow were used all the time to flatten any wholesale power price spike, then there would be a possibility of the Onslow water supply being used up. That would remove the threat of Onslow coming on stream to reduce high spot power prices, and so defeat the whole rationale for Onslow existing in the first place. This means the 'default state' of Onslow must be to remain idle.

A problem that I see is that pumping water into Onslow is going to take a lot longer than releasing that same water downhill to generate power. If water is pumped up the hill at 1cumec/s as an example, it would take 40 hours of pumping to supply a single hour of discharge from one Onslow turbine. I can't help thinking you are going to run out of time to pump all the water you need up there. And remember this pumping will only occur when flow rates into the system are above the median recorded flow rate (apparently). So we will be 'time limited' for pumping up hill.

Unlike Clyde and Roxburgh, Onslow is not a 'run of the river' system. So power can be stored in Lake Onslow for months if necessary. If we can use short sharp rainstorms as periods to pump water up to Onslow that would be great. But wouldn't such storms be more likely to occur in winter when demand for energy is high? This is where I disconnect from the idea of 'river flows above the median' correlating with 'lower power prices'.

If Onslow is generating during times of higher price and lower flows then Clyde would not need to release as much water for Roxburgh as Onslow would be supplying some should the Onslow scheme be above Roxburgh.

So government run Onslow is generating power when prices are high, which means that the Clyde dam is not generating power when prices are high (because both generating power together would overwhelm downstream Roxburgh). How is that good for Contact?

SNOOPY

xafalcon

26-08-2022, 08:31 PM

That is a long response, but I still don't believe you understand the situation.

First, Onslow would not pump, or generate, based on the season, but rather it would do so based on the wholesale price. It is likely that it would be pumping when prices are less than around $50 per MW, and generating when prices are above $100 per MW. Because it can bid (for pumping) and offer (for generation) there would be a number of price bands, not a single price in each direction. It is likely that it would do both: Pumping overnight when prices are low, and generating during the day when prices are high on many days.

Second: The minimum flows are just that, minimum, yet the actual flow through the machines is constantly varying according to dispatch and small variations in frequency. To ensure that the minimum flow is not breached Roxburgh would normally have a minimum offer of 120 MW which is the most efficient load on 3 machines, and gives an outflow of 286 cumecs. The 120 cumec minimum flow is less than can be dispatched on a single machine, but allows for the timing issue of the flow station being 1 1/4 hours flow time downstream while the offer and dispatch process is in half hour increments.

Third: Clutha is a run of River scheme as the storage available at Clyde and Roxburgh is less than can be held for a single day. The median natural inflow at Clyde is 515 cumecs plus any water released from Hawea. If there are median inflows, and minimum water being released from Hawea, and only releasing sufficient water from Clyde to meet the 286 cumecs from Roxburgh, and Lake Dustan level was in the lower 1/4 of its 1 m operating range prior to starting, Clyde would be spilling water within 18 to 22 hours. This is the main definition of Run-of -River: Water reaching the top dam must be passed through within 24 hours.

Fourth: All hydro generators have an efficiency curve, and a flow point per machine where they are most efficient. A single machine at Clyde at 108 MW uses only 1.83 cumecs per MW, but at its minimum load of 70 MW uses 2.03 cumecs per MW. At Roxbugh the range is from 2.43 cumecs per MW at the most efficient point to 2.81 cumecs per MW at the least efficient point. That water saving per MW is a huge incentive to always load machines in most efficient manner possible, and is another reason why minimum flows are seldom targeted.

Clyde is able to shut down for a few hours overnight when flows are low, and doesn't have to supply water to Roxburgh continuously as Roxburgh has around 6 hours of storage.

NZ's power prices are closely linked to inflows, not storage as many seem to believe. When flows are low, as per your calculations in your second paragraph, prices would be high, and Onslow would be generating, not pumping. Thus overnight pumping at Onslow would only occur when there was above median flows in the river. In your final paragraph I think you are confusing the release of water to ensure minimum flows are being maintained Irrespective of price, and pumping for Onslow which would only occur when natural flows are above median and prices are low. If Onslow is generating during times of higher price and lower flows then Clyde would not need to release as much water for Roxburgh as Onslow would be supplying some should the Onslow scheme be above Roxburgh.

If the site selected is blow Roxburgh then the water height for pumping needs to 2.5 times the diameter of the intake pipe.

Thanks for this easy to understand explanation. You certainly have some great knowledge and experience

Drawing on that Knowledge and experience, do you believe Onslow will proceed? What ownership structure would you expect? Is it likely to be a profit driven entity or public good (with construction and operation cost recovery)

On a related note, has grid capacity in south island been/being upgraded to allow all manapouri electricity to be moved north if NZAS closes if a deal can't be made that satisfies EA new rules >150MW?

xafalcon

26-08-2022, 08:34 PM

Snoopy

26-08-2022, 09:31 PM

From what I've read, Onslow is proposed to be 1000MW

I have corrected my post accordingly.

SNOOPY

Snoopy

26-08-2022, 09:47 PM

Drawing on that Knowledge and experience, do you believe Onslow will proceed? What ownership structure would you expect? Is it likely to be a profit driven entity or public good (with construction and operation cost recovery)

Jantar has already commented on this

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=832330&viewfull=1#post832330

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=832306&viewfull=1#post832306

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=843158&viewfull=1#post843158

On a related note, has grid capacity in south island been/being upgraded to allow all Manapouri electricity to be moved north if NZAS closes if a deal can't be made that satisfies EA new rules >150MW?

And this

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=828763&viewfull=1#post828763

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=834149&viewfull=1#post834149

SNOOPY

Snoopy

26-08-2022, 10:51 PM

Interesting little video on the lake Onslow project here:

https://crux.org.nz/deep-south/lake-onslow-4-billion-energy-saviour-or-white-elephant/

SNOOPY

Yottie

26-08-2022, 11:25 PM

ex NSW - or west island ...

Thank you, Snoopy, for those snippets on 2271/2 re Lake Onslow. Most interesting.

Am watching from afar; tho reading most posts. Especially Jantar's as he/she seems knowledgeable.

rgds

Yottie

xafalcon

27-08-2022, 08:13 AM

Jantar has already commented on this

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=832330&viewfull=1#post832330

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=832306&viewfull=1#post832306

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=843158&viewfull=1#post843158

And this

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=828763&viewfull=1#post828763

https://www.sharetrader.co.nz/showthread.php?11636-Power-shares&p=834149&viewfull=1#post834149

SNOOPY

Thanks for that

I find all this very interesting and have been trying to learn as much as I can (from a personal knowledge perspective, I am not a shareholder of any directly related company)

Snoopy

28-08-2022, 10:44 AM

A problem that I see is that pumping water into Onslow is going to take a lot longer than releasing that same water downhill to generate power. If water is pumped up the hill at 1cumec/s as an example, it would take 40 hours of pumping to supply a single hour of discharge from one Onslow turbine. I can't help thinking you are going to run out of time to pump all the water you need up there. And remember this pumping will only occur when flow rates into the system are above the median recorded flow rate (apparently). So we will be 'time limited' for pumping up hill.

I did an internet search on how the 'pumping' side of a pumped hydro-system works. I found lots of information on scheme outputs, but little on scheme inputs. So I have done my own 'back of the envelope' analysis on what might happen.

Looking more into how the pumping side of Onslow might work, took me to the Guinness Book of Records

https://www.guinnessworldrecords.com/world-records/most-powerful-water-pump

"The most powerful water pump pumps at a rate of 60,000 litres per second and was made by Nijhuis Pumps in Winterswijk, Holland, Netherlands, in 2004. The pump is called the Nijhuis-HP1-4000.340"

There are 1,000 litres in a cubic metre. So the capacity of this pump is 60cumecs/s. By contrast an Onslow operating at a maximum of 1,000MW would require 4 x 40cumecs/s = 160cumecs/s of water flowing through the turbines. So the 'flow out'/'flow in' imbalance is a theoretical 2.666:1, which is smaller that I thought. This is all pre-supposing that NZ could afford to install the largest capacity water pump in the world.

There is a problem though

https://actionelectricmotorandpump.com/2019/01/fun-fact-whats-the-largest-pump-in-the-world/

It seems this pump was designed as part of a low lying Netherlands flood protection system. So the head it is pumping might only be 10 metres, and for Onslow we need it to pump water up 600m! Our Nijhuis HP1-4000.340 pump requires 5364hp (4MW) of power to run it at full flow. But comparing the relative pumping heads, you would need 600m/10m = 60 times that figure (240MW) to get water from the Clutha up to Onslow (assuming no pumping system losses which is an unrealistic assumption). Then there are the hydraulic design curve considerations that would surely make the Nijhuis HP1-4000.340 pump unsuitable for a high pumping head application anyway. Not trying to do a design for Onslow here. Just looking at ballpark figures.

There looks to be enough natural flow in the Clutha River (515cumecs/s median) to pump out 60cumecs/s over short time intervals. But it looks to me like you would be looking at the outer limits of pumping technology to balance any outflow from Onslow in a matter of hours.

SNOOPY

Doug

28-08-2022, 12:23 PM

Snoopy you might find this helpful: https://web.engr.oregonstate.edu/~webbky/ESE471_files/Section%203%20Pumped%20Hydro.pdf
Seems combo pump/generator is the way to go today.

Jantar

28-08-2022, 01:50 PM

Snoopy,

Pumped Hydro does not require a separate pump. The Francis turbine acts as generator when water is flowing downhill, but simply swap two of the three phase connections and the generator becomes a motor and that same turbine becomes a pump. (Well not quite that simple as the system has to be synchronised). Modern pumped storage systems are achieving round trip efficiencies greater than 80%, but even older, simpler, designs are still better than 75% efficiency. Pumping is usually at full load, and flow per machine, but generation is usually at the most efficient load, typically 90% load and around 80% flow. In practice, this equates to 1 hr pumping relating to 1 hr generation, but 125 MWh pumping will result in 100 MWh generation.

The proposals for Onslow are 8 machines at 125 MW each (MBIE), 10 machines at 120 MW each (Majeed) and 4 or 6 machines at 250 MW each (NZ Battery). So nothing is yet determined.

Highest water flows in the Clutha catchment occur in mid to late spring, and lowest flows mid to late winter. There is usually a dry settled period in late January to early March, but flows are typically not as low as in winter.

Snoopy

28-08-2022, 07:22 PM

Snoopy you might find this helpful: https://web.engr.oregonstate.edu/~webbky/ESE471_files/Section%203%20Pumped%20Hydro.pdf
Seems combo pump/generator is the way to go today.

Right, I have just spent some time looking over that very informative link (above) from Doug.

Pumped Hydro does not require a separate pump. The Francis turbine acts as generator when water is flowing downhill,

I have realised my brain was over 100 years behind current thinking on pumped hydro. The kind of system I was envisaging, the four unit Quaternary system with a separate Turbine, Generator, Motor and Pump, was out of favour by 1920!

Whereas what you are talking about is a Binary set arrangement: one pump/turbine and one motor/generator (slide 33 in Doug's reference)

but simply swap two of the three phase connections and the generator becomes a motor and that same turbine becomes a pump. (Well not quite that simple as the system has to be synchronised). Modern pumped storage systems are achieving round trip efficiencies greater than 80%, but even older, simpler, designs are still better than 75% efficiency.

According to that reference by Doug, the older systems were more efficient, in hydrological terms anyway. This kind of makes sense. Because the flow conditions going down the hill would be slightly different to the flow conditions going up the hill. So if you have two turbine/pumps, one optimised to the flow conditions uphill and the other downhill, then this would be more efficient. However doubling up on the hardware like this would come at a huge capital cost. So I can understand why modern systems go the single motor/generator, single pump/turbine route.

Slide 39 hints at this too with the Turbine/Pump 'stay vanes' being fixed, while the 'guide vanes' are adjustable and set fully open in pumping mode. If you drop down to slide 57 you will see that pump losses equate to about 10%, but turbine losses are 7.5%. Yet this is the same piece of equipment, but running in the opposite direction.

I also liked the way all the complex algebra came to a very simple conclusion in slide 63. Namely that the 'overall efficiency' of the pumped hydro system can be very simply measured: Take the time of generating an amount of energy, and divide that by the time it takes to put that same energy back up hill. Hey presto, there is your system efficiency!

That Slide 37 is very telling too, on why we would go for the Francis Turbine design. I didn't realise the alternative Pelton Turbine design cannot be used for pumping! Onslow, and the balancing power we want from it, is right in that sweet spot on the head/flow Francis Turbine system design area.

Pumping is usually at full load, and flow per machine, but generation is usually at the most efficient load, typically 90% load and around 80% flow. In practice, this equates to 1 hr pumping relating to 1 hr generation, but 125 MWh pumping will result in 100 MWh generation.

The other way to measure overall system efficiency is to look at the amount of energy transferred each way over a fixed time period. In this example.

100MWh/125MWh = 80%

The proposals for Onslow are 8 machines at 125 MW each (MBIE), 10 machines at 120 MW each (Majeed) and 4 or 6 machines at 250 MW each (NZ Battery). So nothing is yet determined.

Highest water flows in the Clutha catchment occur in mid to late spring, and lowest flows mid to late winter. There is usually a dry settled period in late January to early March, but flows are typically not as low as in winter.

Yes, but weren't you telling us that typically Onslow may switch about on much shorter time frames than seasonal? IOW it might be asked to both generate and pump in a single week during winter?

Back to my reality of being 100 years behind the times. I have just been going over some of Sir Ernest Rutherford's Laboratory notes. Did you know that this crazy man made idea of splitting the atom, might actually be possible?

SNOOPY

P.S. This also means that my work in post 2275 on trying to size a pump is entirely redundant, because in this case the pump is the turbine run in reverse. I think it also means the Guinness Book of Records is wrong. Because there are umpteen pump/turbines set in pumped hydro systems that are a lot more powerful than 'the world's largest pump'. Now, who is going to volunteer to ring them up and tell them?

Snoopy

28-08-2022, 08:17 PM

I've partly sold a large holding on the ASX in the renewable sector and was looking at Contact Energy as a suitable replacement but reading through Snoopy's well researched post it seems I'm better suited to hedge my bets and split between MEL and CEN.

I am talking about Mercury (MCY) and Contact, not Meridian (MEL). But yes, when choices are close, it does pay to hedge your bets and buy a bit of both. It can go against human nature where your instinct is to research, research and research and only buy the best. The trouble is no matter how good your research or advice is, there are always spoiler factors that you cannot control that come in and change the story. Those who preach the diworsification philosophy and go for one two or three stocks only very often come to grief, even if they get plenty of 'likes' on this forum on their journey!

SNOOPY

Jantar

29-08-2022, 09:00 AM

...

Yes, but weren't you telling us that typically Onslow may switch about on much shorter time frames than seasonal? IOW it might be asked to both generate and pump in a single week during winter?.....

SNOOPY

P.S. This also means that my work in post 2275 on trying to size a pump is entirely redundant, because in this case the pump is the turbine run in reverse. I think it also means the Guinness Book of Records is wrong. Because there are umpteen pump/turbines set in pumped hydro systems that are a lot more powerful than 'the world's largest pump'. Now, who is going to volunteer to ring them up and tell them?

The modelling I did for a consulting company that advises MBIE showed that there are times when Onslow could be pumping and generating on the same day, not just the same week. However that does not happen at times of very low flows when it is just generating or off, nor at times of very high flows when it is just pumping or off.

As for the Guinness book of records, It is disputed in a number of places and is no longer really relevant.

Paint it Black

29-08-2022, 03:35 PM

The modelling I did for a consulting company that advises MBIE showed that there are times when Onslow could be pumping and generating on the same day, not just the same week. However that does not happen at times of very low flows when it is just generating or off, nor at times of very high flows when it is just pumping or off.

As for the Guinness book of records, It is disputed in a number of places and is no longer really relevant.

Thanks Jantar and Snoopy - just getting up to speed with the benefits of Onslow and your posts are very informative. One issue to me is the perceived benefits of continuous generation which is being promoted. With more power needed to pump a cu m than is generated from it how does this work? Is the pumping in fact not continuous but only done during off peak with a gradual depletion in storage made up at a time when adequate supply is available from elsewhere? Does the lake have a direct significant catchment to reduce the pumping?

Jantar

29-08-2022, 05:20 PM

Thanks Jantar and Snoopy - just getting up to speed with the benefits of Onslow and your posts are very informative. One issue to me is the perceived benefits of continuous generation which is being promoted. With more power needed to pump a cu m than is generated from it how does this work? Is the pumping in fact not continuous but only done during off peak with a gradual depletion in storage made up at a time when adequate supply is available from elsewhere? Does the lake have a direct significant catchment to reduce the pumping?
Neither pumping, nor generation would be continuous, but would be based on price alone and dispatched by Transpower. As price is closely corelated with hydro inflows and wind strength Onslow would only pump when the wind is blowing and there is plenty of water, and demand is low. It would only generate when there is not much water, wind is light and demand is high. Other times Onslow would be available for either generation, or pumping, but probably wouldn't be needed. The potential storage at Onslow is huge, and would more than double the country's present hydro storage.

Lake Onslow has a small catchment that is currently used for irrigation and to supply Pioneer Generation's small power stations at Horseshoe Bend and Teviot.

GTM 3442

30-08-2022, 07:58 AM

Jantar

30-08-2022, 08:46 AM

Out of idle curiosity, how is the South Island hydro power system fuelled? Yes, I know it's from water, but where does the water come from?

Is it from snowmelt - so that the lakes fill over spring/summer and get emptied over autumn/winter - or from "spring" or underground water which is probably fairly constant - or from rain so there's a bias toward winter/spring inflows?

Or is it a combination?

What happens if the snowmelt gets b*ggered up by global warming/climate change?
It just so happens that this very question is what my Post Grad Cert was based on.

In the South Island hydro catchments there are no underground pseudo catchments, so no ground water component. That means all the water comes from precipitation, although as you point out, some of that precipitation does fall as snow, so its release is delayed from winter into spring and summer. Snowmelt accounts for 7 to 15% of the average spring and summer inflows, but it is far from steady. Many of the spring floods are due to a lot of snow melting at once.

The amount of rain is greatest in the 6 to 8 weeks following each equinox (March and September), and least in summer and winter. This is opposite to further north where most rain falls in winter.

Climate change is, and will, play a very minor part. There will be less snow accumulation in that the snow line moves up by 150 m (500') for every 1 degree increase in temperature. But making up for that, the atmosphere can contain up to 8% more precipital moisture for every 1 degree increase in temperature which evens out the available water over the seasons, reduces drought in mid latitudes, and increases rainfall in rain shadow regions like east of the Southern Alps.

To put that climate change in perspective, for CO2 to cause a 1.2 to 1.6 degree increase in temperature requires a doubling of CO2 concentration, so we aren't going to see that in our lifetimes. However natural causes of climate change are less predictable and could easily cause such a temperature rise, or, even more frightening, a temperature fall.

GTM 3442

01-09-2022, 07:51 AM

Thank you Jantar, much appreciated.

Snoopy

02-09-2022, 08:45 PM

Onslow would not pump, or generate, based on the season, but rather it would do so based on the wholesale price. It is likely that it would be pumping when prices are less than around $50 per MW, and generating when prices are above $100 per MW. Because it can bid (for pumping) and offer (for generation) there would be a number of price bands, not a single price in each direction. It is likely that it would do both: Pumping overnight when prices are low, and generating during the day when prices are high on many days.

Returning to my quest trying to figure out how the profitability of Contact Energy will be affected if Onslow is built....

Contact provides the market with monthly operating reports. The 'Wholesale Market' section contains:

a/ A trailing twelve monthly price trace of 'Wholesale Electricity Pricing' (I am guessing these are averaged over time historical figures) PLUS
b/ A 'current month picture' showing the 'Distribution of Wholesale Market Price' within the reported on trading month.

If we now move to the 'Operational Data' page and cast our eye over the 'wholesale' section, then we get a breakdown in percentage terms of how much energy Contact has generated from Thermal, Geothermal and Hydro generation respectively. Of those three energy generation sources, I expect Thermal and Hydro to be the two that can be 'ramped up' to meet peak demand. When determining peak demand pricing, it will be Thermal that sets the price benchmark. I don't know what the 'profit margin' is for Thermal Energy generated by Contact. However it will be vastly lower than the profit margin on that same incremental energy if it was produced by Hydro. So as a first approximation for this exercise:

c/ I am going to assume that all of Contact's incremental power demand profits, when power prices are high, are generated by its Hydro-electricity assets.

I can estimate the amount of incremental peak power being generated by looking at the 'Distribution of Wholesale Market by Trading period' and noting the percentage of energy generated in the three highest wholesale price bands of $111-$135/MWh, $136-$160/MWh and >$160/MWh. If I then:

d/ Add together the three percentages from the three power price bands I have just described AND
e/ Multiply that percentage total by the total energy generated over the month (calculated from 'Operational data' and summing the energy generated by Thermal Geothermal and Hydro, then I will get a figure for the total energy sold at 'exorbitant prices'.
f/ Next I take the energy sold at 'exorbitant prices' and subtract from that Thermally generated energy. Then what remains (if any) is the Hydro Energy sold at 'exorbitant prices'.

I am going to assume that $160/MWh is an indicative price for our incremental hydro energy to be sold at. Jantar has told us that he expects Onslow to start generating electricity when the price spikes above $100/MWh. We can therefore assume that any energy generated by Contact at the indicative price paid 'today' of $160/MWh will in the future be lost. That is because Onslow will substitute for this exorbitantly priced power from its own power storage which caps the wholesale market price at $100/MWh.

From a Contact Energy perspective, we now know the profit margin per unit of energy not sold at the power price peak that will be lost:

$160/MWh - $100/MWh = $60/MWh

We also know the amount of Hydro energy that will not be sold on market at the exorbitant $160/MWh price (see step f).

So if we multiply:

g/ The power the quantity of power that will not be sold by Contact at the exorbitant price by
h' the incremental price drop of $60/MWh,

then this will give a good indication of the wholesale power profit lost to Contact, as a result of Onslow being operational, for that month. Do this for each of the twelve months of the year, and sum the results. You will then have a measure -in dollar terms- of the annual energy not sold at exorbitant incremental rates.

With hydro-energy, opening and closing the turbine gates are part of normal operations. So the timing of exactly when the water moves through the turbines will not affect the wear and tear on those turbines. IOW there will be no 'incremental depreciation' at the Contact dams because of Onslow. Neither will Contact's interest on debt change according to when Onslow operates. So IMO it is more correct to think about Onslow affecting profits at EBITDAF level, and not NPAT level.

So there is my method for measuring the effects of Onslow on Contact Energy profits outlined. Now let's see if I can put it all into practice.

SNOOPY

Wright

03-09-2022, 10:21 AM

Not sure if this has been posted before re Onslow:

https://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&cd=&ved=2ahUKEwjuucPekPf5AhVC4nMBHStJCzQQFnoECAQQAQ&url=https%3A%2F%2Fwww.mbie.govt.nz%2Fdmsdocument%2 F23346-update-on-the-new-zealand-battery-project-proactiverelease-pdf&usg=AOvVaw197J2La0ZtjMqlbdqaGUDr

Jantar

04-09-2022, 08:56 AM

Returning to my quest trying to figure out how the profitability of Contact Energy will be affected if Onslow is built.... ..

SNOOPY
Yes, this is the big question that we all would like to know. But it isn't just Contact that will be affected, but also Genesis.

The Government have decreed that all fossil fuelled generation is to be shut down, and this is the main reason for wanting a large storage system. Effectively Onslow will replace thermal generation, and will be priced similar to where current thermal generation is.

I used $100 as a possible starting point for Onslow as that is close to the offer price for the cheapest thermal generation at present. That doesn't mean that all Onslow generation would be at that price, only the first of ten tranches. If the first tranche, say 108 MW is offered at $100, the next tranche would likely be $120. Then go up in increasing price gaps until the last trance is around $450, the approximate price for Whirinaki generation. Thus Onslow does not place a hard cap on prices, but a soft cap that increases with scarcity of other generating offers and demand.

The other end of the price scale is also important. Because not only would Onslow provide a type of cap to the higher prices, but also puts a soft floor on the lower prices. It would start buying power from the grid for pumping when prices are low, thus increasing the demand when generation offers are plentiful and demand is low. If Generation offers were to start at $100 then pumping bids would probably start at $50 for the first trance of 120 MW, and reduce the price in the next 9 tranches until the 10th tranche would be bid at around $1 or less.

Overall, the average price for generation would be similar to the average thermal price at present, but without the huge spikes that sometimes hit the wholesale market, thus giving a slightly reduced price at the top end. Similarly, the lower prices would be raised slightly, thus eliminating the $0.01 prices often paid to wind and geothermal generators and giving them more certainty of receiving reasonable prices for that renewable generation.

All this means that your paragraphs f/ and g/ calculations also need to allow for the gain in lower prices. Not covered in those calculations is the fact that Contact is heavily hedged by its retail book, and the number of ToU customers to the extent that it often struggles to meet that hedge position when prices are high. I am not sure how you will account for that hedging in your calculations.

Jantar

04-09-2022, 09:05 AM

Not sure if this has been posted before re Onslow:.....
I have had a copy of this document for a couple of weeks, but didn't realise it had already been made public. Thank you for linking to that.

Note paragraphs 37 and 38 deal with what we have been discussing here. We have even delved into the redacted part in 38.1, but without the exact details.

Snoopy

04-09-2022, 09:29 AM

So there is my method for measuring the effects of Onslow on Contact Energy profits outlined. Now let's see if I can put it all into practice.

Wholesale Power Price Effect of potential Onslow on Contact Energy (FY2022 re-modelled retrospectively)

Month
Percentage of Wholesale Power Priced > $111MW/h {A}
Total Energy Generated (GWh) {B}
Energy Generated > $111MW/h (GWh) {A}x{B}
Thermal Energy Generated {C} (GWh)
Hydro Energy Generated > $111MW/h (GWh) {A}x{B}-{C}
Onslow Lost Wholesale Value to Contact Energy @ $60MW/h

June 2022
70%
760
532
165
367
$22.02m

May 2022
100%
692
692
141
551
$33.06m

April 2022
95%
597
567
139
429
$25.68m

March 2022
90%
637
573
156
417
$25.02m

February 2022
60%
566
340
37
303
$18.18m

January 2022
70%
606
424
48
376
$22.56m

December 2021
10%.
664
66
22
44.
$2.64m

.
November 2021
5%
666
33
15
18
$1.08m

October 2021
10%
710
71
25
46
$2.76m

September 2021
20%
696
139
36
103
$6.18m

August 2021
53%
763
404
76
328.
$19.68m

July 2021
75%
911
683
186
497
$29.82m.

Total

.

$208.68m

Calculation Notes.

1/ The "Percentage of Wholesale Power Priced > $111MW/h" (table column 1) is arrived at by looking at the monthly "Distrbubution of wholesale market price by trading periods" (from each of twelve Monthly Operating Reports) 'bar graph' top three pricing categories: $111-135, $136-160 and >$160, for the Otahuhu electricity market power pricing node. Next, I add together the three 'bright red bars', representing the current month, by eye. Then I write down the 'cumulative total percentage figure' to an accuracy of about 5%. Next, I do the same exercise for the 'Benmore power pricing node'. I average the two results to get a final 'representative percentage'.

---------------

EBITDAF for Contact Energy over FY2022 was $537m. So taking $209m off that figure, reduces EBITDAF to:

$537m - $209m = $328m = OUCH!

This is a massive potential hit coming up for Contact shareholders (and all shareholders of gentailers in fact).

My modelling is somewhat simplistic and Jantar, in post 2288, has pointed out a couple of obvious weaknesses.

1/ There would be a consummate 'upping of supply bids' at the lower end of the power price scale, for pumping. Getting more money at the lower end of the power pricing cycle would be good for Contact Energy.
BUT (1 Counterpoint)/ If you look at the distribution of power pricing, in most instances of 'wholesale power pricing' it is the upper figure range of >$160MW/h that dominates. But in reality power pricing at the peak can go much higher than $160/MWh. So there is a good chance I have underestimated the real loss in wholesale power price peaking that Contact would incur, by using that $160MW/h figure, should Onslow become operational.
2/ If Contact is being paid less for their wholesale power, then the retail side of the gentailer business becomes more profitable. So some of that 'loss in wholesale power profit' would be clawed back at the retail end.
BUT (2 Counterpoint)/ Retail is a less capital intensive business to enter and competition is more intense than in the wholesale space. The reduction in 'wholesale power price spikes' should make competitor retail businesses easier to operate profitably and sustainably. Thus I would expect retail competition to intensify 'over the medium term', if Onslow goes ahead. And that means lower profit margins for the existing gentailers' retail arms over time.

At this point there are lots of factors to consider. But even if the real loss to Contact is only half of that my somewhat crude calculation assessment, a '$100m hit' to EBITDAF is still pretty substantial. This exercise is making me think again about what premium I should pay for having shares in these gentailers for their supposed 'certain future cashflows' going forwards.

SNOOPY

Snoopy

04-09-2022, 08:31 PM

Not covered in those calculations is the fact that Contact is heavily hedged by its retail book, and the number of ToU customers to the extent that it often struggles to meet that hedge position when prices are high. I am not sure how you will account for that hedging in your calculations.

I imagine you are talking about Time of Use customers, who make a commitment to only draw power at hours when the power price is low? But of course the weather gods do not always play by the book. So there may be occasions where Contact has to supply power at what were forecast to be 'low rate times', when the actual power demand was high (meaning cost of supply exceeds the price Contact have contracted to supply).

I am not sure if you are talking about Contact further hedging this risk. Or if you are talking about the supply agreement itself being the hedge (from a power consumer perspective).

My general policy is to take out all hedge deals when evaluation a company's profitability. My reasoning being that these are all 'zero sum games'. Thus while Contact may do well out of such deals in some years, the weather patterns may see the same deals backfire in other years. Thus -long term- the expected contribution of hedge deals to any company's profitability is a net zero.

SNOOPY

Snoopy

04-09-2022, 10:04 PM

Having already done the exercise below for FY2022, I thought it worth repeating the process for FY2021, in case FY2022 was a 'rogue data year'. The fact that power shortages have been in the headlines this winter (FY2022) might suggest that it was merely unusual weather patterns that were causing unusual wholesale power price spikes. So what happened over FY2021 at Contact Energy?

Wholesale Power Price Effect of potential Onslow on Contact Energy (FY2021 re-modelled retrospectively)

Month
Percentage of Wholesale Power Priced > $111MW/h {A}
Total Energy Generated (GWh) {B}
Energy Generated > $111MW/h (GWh) {A}x{B}
Thermal Energy Generated {C} (GWh)
Hydro Energy Generated > $111MW/h (GWh) {A}x{B}-{C}
Onslow Lost Wholesale Value to Contact Energy @ $60MW/h

June 2021
90%
806
725
184
541
$32.46m

May 2021
95%
810
770
220
550
$33.00-m

April 2021
93%
662
629
185
464
$27.84m

March 2021
90%
593
534
77
457
$27.42m

February 2021
90%
532
479
54
425
$25.50m

January 2021
55%
626
344
22
322
$19.32m

December 2020
50%.
578
289
27
262.
$15.72m

.
November 2020
38%
604
230
54
176
$10.56m

October 2020
55%
659
362
81
281
$16.56m

September 2020
63%
801
505
179
326
$19.56m

August 2020
43%
869
374
251
123.
$7.38m

July 2020
60%
866
520
278
242
$14,52m.

Total

.

$250.14m

Calculation Notes

1/ The "Percentage of Wholesale Power Priced > $111MW/h" (table column 1) is arrived at by looking at the monthly "Distrbubution of wholesale market price by trading periods" (from each of twelve Monthly Operating Reports) 'bar graph' top three pricing categories: $111-135, $136-160 and >$160, for the Otahuhu electricity market power pricing node. Next, I add together the three 'bright red bars', representing the current month, by eye. Then I write down the 'cumulative total percentage figure' to an accuracy of about 5%. Next, I do the same exercise for the 'Benmore power pricing node'. I average the two results to get a final 'representative percentage'.

---------------

EBITDAF for Contact Energy over FY2021 was $553m. So taking $250m off that figure, reduces EBITDAF to:

$553m - $250m = $303m = DOUBLE OUCH!

This shows that the 'massive potential hit' that showed as an example of what might happen to Contact Energy profitability in the future (post 2290) was likely not a one off rogue event based on unusual weather conditions.

SNOOPY

Jantar

04-09-2022, 10:15 PM

I imagine you are talking about Time of Use customers, who make a commitment to only draw power at hours when the power price is low? But of course the weather gods do not always play by the book. So there may be occasions where Contact has to supply power at what were forecast to be 'low rate times', when the actual power demand was high (meaning cost of supply exceeds the price Contact have contracted to supply).

I am not sure if you are talking about Contact further hedging this risk. Or if you are talking about the supply agreement itself being the hedge (from a power consumer perspective).

My general policy is to take out all hedge deals when evaluation a company's profitability. My reasoning being that these are all 'zero sum games'. Thus while Contact may do well out of such deals in some years, the weather patterns may see the same deals backfire in other years. Thus -long term- the expected contribution of hedge deals to any company's profitability is a net zero.

SNOOPY
ToU customers do not just draw when prices are low, bur pay a different price depending on whether they are taking energy during a business day, non business day, or at night.

But the real hedge is the retail book. Retail customers pay a fixed price irrespective of the wholesale price, and make up a very large part of any Gentailers energy sales. There is only a very small part of the company's generation that is fully exposed to the wholesale market. I don't know what it is now, but it used to be only around 10% exposure. There were many times that we would be scrambling trying to buy 50 or 100 MW on a short term CFD from another gentailer. Similarly there were many times that another gentailer would be begging us for a contract.

Jantar

05-09-2022, 08:44 AM

Wholesale Power Price Effect of potential Onslow on Contact Energy (FY2022 re-modelled retrospectively)

Month

Percentage of Wholesale Power Priced > $111MW/h {A}

Total Energy Generated (GWh) {B}

Energy Generated > $111MW/h (GWh) {A}x{B}

Thermal Energy Generated {C} (GWh)

Hydro Energy Generated > $111MW/h {A}x{B}-{C}

Onslow Lost Wholesale Value to Contact Energy @ $60MW/h

June 2022

70%

760

532

165

367

$22.02m

May 2022

100%

692

692

141

551

$33.06m

April 2022

95%

597

567

139

429

$25.68m

March 2022

90%

637

573

156

417

$25.02m

February 2022

60%

566

340

37

303

$18.18m

January 2022

70%

606

424

48

376

$22.56m

December 2021

10%

664

66

22

44

$2.64m

November 2021

5%

666

33

15

18

$1.08m

October 2021

10%

710

71

25

46

$2.76m

September 2021

20%

696

139

36

103

$6.18m

August 2021

53%

763

404

76

328

$19.68m

July 2021

75%

911

683

186

497

$29.82m

Total

$208.68m

Notes.

1/ The "Percentage of Wholesale Power Priced > $111MW/h" (table column 1) is arrived at by looking at the monthly "Distrbubution of wholesale market price by trading periods" (from each of twelve Monthly Operating Reports) 'bar graph' top three pricing categories: $111-135, $136-160 and >$160, for the Otahuhu electricity market power pricing node. Next, I add together the three 'bright red bars', representing the current month, by eye. Then I write down the 'cumulative total percentage figure' to an accuracy of about 5%. Next, I do the same exercise for the 'Benmore power pricing node'. I average the two results to get a final 'representative percentage'.

---------------

EBITDAF for Contact Energy over FY2022 was $537m. So taking $209m off that figure, reduces EBITDAF to:

$537m - $209m = $328m = OUCH!

This is a massive potential hit coming up for Contact shareholders (and all shareholders of gentailers in fact).

My modelling is somewhat simplistic and Jantar, in post 2288, has pointed out a couple of obvious weaknesses.

1/ There would be a consummate 'upping of supply bids' at the lower end of the power price scale, for pumping. Getting more money at the lower end of the power pricing cycle would be good for Contact Energy.
BUT (1 Counterpoint)/ If you look at the distribution of power pricing, in most instances of 'wholesale power pricing' it is the upper figure range of >$160MW/h that dominates. But in reality power pricing at the peak can go much higher than $160/MWh. So there is a good chance I have underestimated the real loss in wholesale power price peaking that Contact would incur, by using that $160MW/h figure, should Onslow become operational.
2/ If Contact is being paid less for their wholesale power, then the retail side of the gentailer business becomes more profitable. So some of that 'loss in wholesale power profit' would be clawed back at the retail end.
BUT (2 Counterpoint)/ Retail is a less capital intensive business to enter and competition is more intense than in the wholesale space. The reduction in 'wholesale power price spikes' should make competitor retail businesses easier to operate profitably and sustainably. Thus I would expect retail competition to intensify 'over the medium term', if Onslow goes ahead. And that means lower profit margins for the existing gentailers' retail arms over time.

At this point there are lots of factors to consider. But even if the real loss to Contact is only half of that my somewhat crude calculation assessment, a '$100m hit' to EBITDAF is still pretty substantial. This exercise is making me think again about what premium I should pay for having shares in these gentailers for their supposed 'certain future cashflows' going forwards.

SNOOPY

Snoopy, there is so much wrong with this analysis that it is not fit for any purpose. Some of this I have already commented on, but lets look at just the June 2022 report to show up a bit more of it.

Your figures give total generation of 760 GWh, which is correct. But look at the line of the report that says Contracted Electricity Sales of 751 GWh. That only leaves 9 MWh exposed to the wholesale market, a long way from the whole 760 GWh.

There is absolutely no reason to say that all generation above $111 per MWh should be capped at that price. Onslow would place a soft cap, not a hard cap on prices. Overall wholesale prices above the start price of Onslow generation would be lower, . At the other end of the scale, wholesale prices lower than the start price of Onslow pumping would be higher, but again would not have a fixed limit. You have not included that aspect in your calculations. Nor have you included the savings in gas purchases due to there being no thermal generation in the market.

RTM

05-09-2022, 10:54 AM

Snoopy

05-09-2022, 07:02 PM

Your figures give total generation of 760 GWh, which is correct. But look at the line of the report that says Contracted Electricity Sales of 751 GWh. That only leaves 9 MWh exposed to the wholesale market, a long way from the whole 760 GWh.

Let's take one step back just to be clear what that table I posted using 2022 information (my post 2290) is meant to show. It is what I term a 'scenario analysis'. It answers the question:

------------------------

1/ If the core generating capacity at Contact Energy remained 'as is' in the future, -AND-
2/ If the climate and demand picture in NZ produced the same energy from Contact owned generation assets as was delivered over FY2022 (but with thermal assets removed, and replaced by baseload geothermal assets) -AND-
3/ Onslow was built and operating, and selling into the power market energy at an average price of $100/MWh whenever the Onslow start up delivery price signal would be triggered by a third party lowest offer market price at $111/MWh - or more -

THEN what would be the effect on Contact Energy's profits?

---------------------

I see that figure of 760GWh total generated over June 2022 in FY2022 Jantar (from the monthly June report), which is exactly the same figure that would be generated in my scenario analysis. But that second figure you mention of 751GWh in the reporting information, that 751GWh figure was the energy contracted for sale in June 2022. That figure is not relevant to this discussion, because I am talking about some future June of a year that will come when Onslow is operating. Whatever happened back in June 2022, in terms of contracted sales demand, will not be the same figure in the future June I am looking at. And it is the future we are talking about here.

Now fast forward to this 'future June'. Will there be a large proportion of these wholesale sales signed off under contract? We don't know for sure, but probably. And what price will these contracts be signed off at? I would imagine it will be based around a forecast future spot price series, averaged over the length of the contract. And Contact will probably throw in a discount, to account for the fact that their wholesale customer(s) have committed to Contact Energy as a supplier for a fixed term. Come the day, the actual contracted power price for wholesale customers may not equal the spot market price. I would go so far as to say it almost certainly won't. But without knowing the future, the best tool for forecasting the future is the seasonally adjusted projected spot price curve. So for this reason, I do not think it is unreasonable to forecast future customer demand and sales prices - whether contracted or not - that are based on the expected spot price. The way I look at things, those future 'wholesale contract prices' are still 'at risk'. It is just that the risk has been taken out at a different (earlier) stage of the power sales process, rather than 'pay on the day' at spot rates. Given this, I don't think it is unreasonable to suggest that future demand pricing - including that in sales contracts yet to be inked - is best estimated by 'spot pricing'. IOW the projected EBITDAF loss that I am forecasting for Contact Energy is the relevant figure.

There is absolutely no reason to say that all generation above $111 per MWh should be capped at that price. Onslow would place a soft cap, not a hard cap on prices. Overall wholesale prices above the start price of Onslow generation would be lower, .

You are right of course. If you had a 'soft cap', then you would get a distribution of offered prices. So what I have done is to make a simplifying assumption. I am saying is that the 'volume weighted average of trigger prices' that would see Onslow 'start generation' would be $111/MWh. 'On average' over all the times Onslow was started, the time weighted average of power sold would flow onto the market at $100/MWh. But these figures are averages that do not necessarily reflect the trigger price, nor the selling price, of any individual Onslow generation event.

Nor have you included the savings in gas purchases due to there being no thermal generation in the market.

Good point. I see from the 'operational data' listed information that 1.3PJ of gas was used for 'internal generation.'

But where do I find the dollar figure associated with that? I can't see it declared separately in the monthly operational report.

SNOOPY

Snoopy

05-09-2022, 08:02 PM

At the other end of the scale, wholesale prices lower than the start price of Onslow pumping would be higher, but again would not have a fixed limit. You have not included that aspect in your calculations.

I wasn't going to go into detail on the 'buy side' upside of Onslow for Contact Energy. The reason for that will become apparent. But since Jantar specifically mentioned it, I have decided to put the bonus 'buy side' table on this thread after all.

I am assuming that Onslow will start buying electricity for pumping once the trigger power price signal drops below $35/MWh. I am assuming Onslow on average, will pay $50/MWh for pumping purposes. This will provide a net benefit to Contact Energy of:

$50/MWh - $35/MWh = $15/MWh for each MWh purchased from Contact.

So what dollar value benefit will Contact receive if Onslow pumps according to this plan?

Wholesale Power Price Effect of potential Onslow on Contact Energy (FY2022 re-modelled retrospectively)

Month
Percentage of Wholesale Power Priced < $35MW/h {A}
Total Energy Generated (GWh) {B}
Energy Generated < $35MW/h (GWh) {A}x{B}
Onslow Gain in Wholesale Value for Contact Energy @ $15MW/h

June 2022
6.5%
760
49
$0.74m

May 2022
0%
692
0
$0m

April 2022
0%
597
0
$0m

March 2022
0%
637
0
$0m

February 2022
23%
566
130
$1.95m

January 2022
2.5%
606
15
$0.23m

December 2021
37.5%.
664
249.
$3.74m

.
November 2021
10%
666
67
$1.01m

October 2021
30%
710
213
$3.20m

September 2021
18%
696
125
$1.88m

August 2021
22%
763
168.
$2.52m

July 2021
2.5%
911
23
$0.35m.

Total

$15.62m

Calculation Notes.

1/ The "Percentage of Wholesale Power Priced < $35MW/h" (table column 1) is arrived at by looking at the monthly "Distrbubution of wholesale market price by trading periods" (from each of twelve Monthly Operating Reports) 'bar graph' in the bottom category < $35MW/h, for the Otahuhu electricity market power pricing node (the three 'bright red bar', representing the current month. I write down this figure to an accuracy of about 5%. Next, I do the same exercise for the 'Benmore power pricing node'. I average the two results to get a final 'representative percentage'.

---------------

The gain for Contact Energy is assuming the weighted average pumping price paid to Contact Energy is $50/MWh, providing a $15MW/h incremental margin over the price that without Onslow, Contact might have otherwise expected to get for that same energy. In practice, and if Jantar's story about some run of the river hydro energy being sold for as low as a few cents per MWh is true, the actual return for Contact could be double what I am modelling here, say $30m.

But such an amount, although substantial, is still within the error bound of the downside of Onslow for Contact. I have estimated the downside figure, that must be offset against this upside to be $208m. But it could be much higher, approaching $300m. IOW the upside is more than covered by the uncertainty of the error bar around the downside. That means I have wasted my time working out the upside because it has no significance in the big picture. I could see this was going to happen before I started the upside calculation, which is why I didn't do it. However, I appreciate that not everyone can see this in advance, which is why I have done the upside calculation for all to see - so they can appreciate it wasn't worth doing.

SNOOPY

Jantar

06-09-2022, 08:54 AM

Snoopy

06-09-2022, 10:01 AM

Thanks Snoopy.

I see you are starting to see some of the pricing issues, but you have somehow put them the wrong way round.

Lets start with "3/ Onslow was built and operating, and selling into the power market energy at an average price of $100/MWh whenever the Onslow start up delivery price signal would be triggered by a third party lowest offer market price at $111/MWh - or more -"

The startup point of any generator is when they are dispatched by Transpower, and that dispatch is set according to the offer price. Here is a Bid/Offer scenario I set up for a 960 MW Onlsow. I can show this one as it not one of options under consideration. As you can see from this stack there is no possible way that the average generation price can be lower than the initial generation price.

14129

Under this Bid/Offer stack, Onslow would first be dispatched when the nodal price reached $104, and the quantity dispatched at that price would increase until it reached 108 MW. At that point Transpower would dispatch the next highest offer, which may be Onslow, or may be another hydro station belonging to another party. As the nodal price increases to $130 then the next machine at Onslow would be dispatched in increasing quantities until the dispatched quantity reached 207 MW. Again, at that point Transpower would dispatch the next highest offer, which may be Onslow, or may be another hydro station belonging to another party. This dispatch process is repeated until at a nodal price of above $619.90 all 960 MW of Onslow is dispatched.

I need to explain a bit more about my modelling that has the dispatch price of 'greater than $111/MWh' verses the 'signal price' (startup point) which determines when the turbine starts up of $100/MWh in my power pricing scenario.

I chose that $111/MWh figure because the "Distribution of wholesale market price by trading periods" is listed under grouped power price bands in the Contact monthly Operating Report as follows:

<$35, $36-$60, $61-$85, $86-$110, $111-$135, $136-$160, >$160

Taking the $100/MWh as a figure that you Jantar, suggested might be the starting point for dispatch from Onslow, I noticed that figure lay in the middle of the $86-$110 band. So the question I asked myself was, if the power generation market was operating in that band, would there be generation from Onslow or not? The answer being 'yes' if the matched price was above $100, but 'no' if the matched price was below $100. It was a function of the way that the power price grouping was made, between $86 and $110, that meant it was impossible to know whether power would be dispatched or not with dispatch market pricing in that price band. So I then moved up to the next price band where there would not be such a yes/no dilemma.

If the start up price was between $111 and $135 (or one of the two higher bands), then in those I cases I could be sure that Onslow would be started up (if the minimum targeted dispatch price from Onslow was $100).

Jantar you say
"there is no possible way that the average generation price ($100/MWh) can be lower than the initial generation price ($111/MWh)."

Yes I get this. So what I needed was the percentage of generation for the month with a wholesale market price of >$100/MWh. But unfortunately that figure is not available from the Contact monthly reports. So I had to move up to the next price band, starting at $111MWh+ to make sure that Onslow would be generating.

This means that if we stick to your >$100/MWh Onslow generation start point, my figures will be underestimating the generation from Onslow. That is because I will not be counting the generation that occurs between $100/MWh and $110/MWh part of the lower category $86-$110 power band.

To be clearer, what I should have done is said that my estimate of power generation from Onslow that would be dispatched when the dispatch market price was greater than $100/MWh was equal to the percentage of power generated across the three higher power price bands ($111-$135, $136-$160, >$160) added up together, while at the same time noticing that this was an 'under-reporting total', (because it did not include power generated in the $100-$110 band that was not separately disclosed). If I had said that, then the average generation price assumed of $100/MWh would not have been less than the initial generation price -that it looked like I was claiming to be $111/MWh-, (but in fact was $100/MWh in my own mind at least).

This also means that in my post 2290, the $208.68m of 'lost value' for Contact would be an underestimate. Because I did not account for the energy that Onslow was putting back into the Clutha River when the wholesale power price was between $100/MWh and $110/MWh.

SNOOPY

Jantar

06-09-2022, 10:41 AM

I need to explain a bit more about my modelling that has the dispatch price of 'greater than $111/MWh' verses the 'signal price' (startup point) which determines when the turbine starts up of $100/MWh in my power pricing scenario.

I chose that $111/MWh figure because the"Distribution of wholesale market price by trading periods" is listed under grouped power price bands as follows:

<$35, $36-$60, $61-$85, $86-$110, $111-$135, $136-$160, >$160

Taking the $100/MWh as a figure that you Jantar, suggested might be the starting point for dispatch, I noticed that figure lay in the middle of the $86-$110 band. So the question I asked myself was, if the power generation market was operating in that band, would there be generation from Onslow or not? The answer being 'yes' if the matched price was above $100, but 'no' if the matched price was below $100. It was a function of the way that the power price grouping was made, between $86 and $110, that meant it was impossible to know whether power would be dispatched or not with pricing in that band. So I then moved up to the next price band.

If the start up price was between $111 and $135 (or one of the two higher bands), then in those I cases I could be sure that Onslow would be started up if the targeted dispatch price was $100.

Correct, but that only relates to first dispatch of the first machine. So that cannot be the average price received, nor the capping price. If the offer price was $100 for the first tranche then a maximum of 9% of Onslow's capacity would be dispatched at that price. About equivalent to a single Stratford peaker, so that cannot set a maximum wholesale price.

Muse

06-09-2022, 12:19 PM

Jantar

06-09-2022, 01:23 PM

This is all good stuff thank you Snoopy & Jantar, even though it's well over my head and I feel like a child who has walked into the middle of an adult's conversation.

Onslow feels like quite a risk to the make-up and long term pricing that gentailers are able to achieve, and thus yields and valuations.

Jantar what's your gut feel for the chances it goes ahead, and if it does, your gut feel for how the economics are captured (IE, owned and operated by various existing generators, or owned by a new government entity)

If it goes ahead and is structured as a new gov entity would be a bit of a disaster for gentailer shareholders, no?

I enjoy my CEN and GNE shares as much as anyone else, but makes me feel a bit nervous having this on the horizon. And we do have in place a government who won't feel too much sympathy for what it would do to shareholders and kiwisaver balances.

Anyone know if National have a position statement on it?
About whether or not it goes ahead, look at it this way: If the government are serious about decarbonising the electricity industry, then it must go ahead or our national grid will collapse. We simply cannot replace load following thermal generation with base load geothermal and intermittent wind power.

What many people are missing is that pumped storage is not an energy source,it is a power source. We do not gain any energy by pumping water uphill then using it to generate later. But renewable types of generation like geothermal and wind are energy sources, and only partially are they power sources. Pumped storage is means of storing energy at a time when there is plenty to use later when it is needed.

Tonight, Transpower have already issued warnings of insufficient offers of generation. I.e. Not enough power over the peak, and that is even with a lot of thermal plant offered. Take that thermal out of the equation and there will be blackouts. Onslow would replace that thermal plant by storing energy in advance and using it when needed.

The NZ Battery project are looking at other forms of energy storage, but so far none come close to Onslow in terms of energy density for the price.

There are a number of ways that Onslow could be structured. In order of effectiveness they are:
1. Owned and operated by one of the current gentailers. Comments by both Contact and Meridian appear to rule out this.
2. A new SOI. Owned by the government, just like Transpower is, but operated completely at arms length.
3. Public/Private Partnership: The Government builds it, but it is operated by a gentailer who pay the government for that right. Modelling so far suggests that this method would be a risk for the gentailer as in some years the income from Onslow would not cover the payments required by the government.
4. Owned by the government who pay a fee to a power company to operate and offer under strict guidelines. This is what happened with Whirinaki in the early 2000s, and proved to be a disaster for the market.

Muse

06-09-2022, 01:40 PM

About whether or not it goes ahead, look at it this way: If the government are serious about decarbonising the electricity industry, then it must go ahead or our national grid will collapse. We simply cannot replace load following thermal generation with base load geothermal and intermittent wind power.

What many people are missing is that pumped storage is not an energy source,it is a power source. We do not gain any energy by pumping water uphill then using it to generate later. But renewable types of generation like geothermal and wind are energy sources, and only partially are they power sources. Pumped storage is means of storing energy at a time when there is plenty to use later when it is needed.

Tonight, Transpower have already issued warnings of insufficient offers of generation. I.e. Not enough power over the peak, and that is even with a lot of thermal plant offered. Take that thermal out of the equation and there will be blackouts. Onslow would replace that thermal plant by storing energy in advance and using it when needed.

The NZ Battery project are looking at other forms of energy storage, but so far none come close to Onslow in terms of energy density for the price.

There are a number of ways that Onslow could be structured. In order of effectiveness they are:
1. Owned and operated by one of the current gentailers. Comments by both Contact and Meridian appear to rule out this.
2. A new SOI. Owned by the government, just like Transpower is, but operated completely at arms length.
3. Public/Private Partnership: The Government builds it, but it is operated by a gentailer who pay the government for that right. Modelling so far suggests that this method would be a risk for the gentailer as in some years the income from Onslow would not cover the payments required by the government.
4. Owned by the government who pay a fee to a power company to operate and offer under strict guidelines. This is what happened with Whirinaki in the early 2000s, and proved to be a disaster for the market.

Thanks Jantar. Very interesting and appreciate you taking the time to offer your expertise.

I get the feeling the market is more or less ignoring the potential impact of Onslow on the make-up and economics of the power industry, particularly with high yields on offer. Too difficult to understand, and can only play what is in front of you, I suppose. But there is a developing risk here and not a small one to the yields and prices of our beloved gentailers. Maybe some of those +6% bond yields coming to the market or being yielded on the NZDX are a place to hedge some bets.

It's not impossible with new builds coming on stream along with some collective punt/hope that hydrogen (or other new technology, or a step change in capability of an existing technology) will come to play that onslow isn't pursued. If prices rise as they are tawai point could be shut, and release that energy to the market. With something this big its difficult to see the price signals working to initiate new builds, but maybe that's the idea, because we wont have to if onslow is built. It's sorta like a big game theory, how rational participants will act and build, coupled with politics!

I dont understand it. Will hide under my blanket for now with my existing shares, maybe look elsewhere for my new "safe" yielding investments I want to make.

Norwest

06-09-2022, 08:56 PM

Onslow will still be being talked about in 10 years time, it's not worth worrying about Moose.

Snoopy

10-09-2022, 02:11 PM

(5) AR2022 Note A3 states Stay In Business (SIB) capital cashflow of $75m over FY2022. I have applied a 20% surcharge on this value to get an estimate of $85m for the total stay in business capital charge applicable to FY2022. Unlike previous years, overall SIB capex was not disclosed for FY2022 (except from AR2022 p60 'SIB Capex more than FY2021').

I am not happy with my guesstimate 'surcharge correction' referred to above (meaning I don't think I should have to guess what it is).

It is very disappointing how the Stay In Business (SIB) cashflow at Contact Energy has become opaque over FY2022. I say disappointing because dividends are based on 'operating free cashflow'. If you don't understand what the SIB capex is and how it is calculated, then you cannot calculate 'operating free cashflow'. So I am using this post to pull together a few clues to see if I can work it out.

If I look on slide 32 of the 21st June 2022 International Roadshow Presentation

https://contact.co.nz/-/media/contact/mediacentre/presentations/2022-international-roadshow-presentation.ashx?la=en

(to put this in context the roadshow was put together before the FY2022 results were announced) talking about Tauhara, I find in the fine print at the bottom of slide 32 explaining 'Estimated forward capital expenditure (cash) of $390 the following 'clarification':

"1/ Excluding capitalised interest as at 31 May 2022. $550m as of 31 December 2021"

Maybe I have a comprehension problem or something, but I find it difficult to understand what that note 1 means. Is it saying:

a/ The estimated forward capital expenditure as at 31st December 2021, (the last disclosed reporting date) was $550m? That means $550m-$390m= $160m of capex on Tauhara was spent between 1st January 2022 and 31st May 2022 (with no implied comment on quantifying capitalised interest) OR

b/ $390m excluding capitalised interest on the Capex budget is the money still to spend? But when you add back the estimate of capitalised interest to be spent over the capital expenditure total, then that total comes to $550m (using interest capitalisation charges as forecast on 31st December, being the last declared set of results)

Next "Note 2" is a qualifying comment on an estimate of the net costs of generation.

"2/ Includes operating costs, carbon costs and stay-in-business capex (excluding make-up drilling and major mid-life capex replacement)"

My understanding of 'make up drilling' is boring an additional hole (or holes) into the geothermal field as a supplementary or new feed - to heighten a reduced temperature and pressure energy source in order to restore the feed of an existing geothermal turbine back to its design operating specification. This is not an unusual thing to require. In fact since the broader Wairakei/Tauhara geothermal field (incorporating Contact's Wairakei, TeMihi and Poihipi Road, combined with Te Huka and soon to be built Tauhara) has been being tapped for 64 years, that means make up drilling would be expected, (I would think). So how can you exclude 'make up drilling' from SIB capex? That doesn't make sense to me.

Or have they folded 'make up drilling' and 'major mid-life capex replacement' into construction costs for development capex, into the Tauhara project?, (as expanded on in foot note 3, quoted below).

"3/ The total addition to PPE on Tauhara commissioning will include ~$18m capitalised transmission asset, ~$80m of capitalised interest ($27m sunk) and $24m of residual sunk capex related to the next phase of development of the field expected total of $940m ($818m + $18m + $80m + $24m)"

So $818m is the Total Estimated Construction cost for Tauhara, which doesn't include a whole lot more costs that are going to be tacked onto this total, which means the real total is $940m, not $818m. I hate to sound cynical but, what kind of construction cost reporting is this?

The main point that I find baffling is the apportioning of 'capitalised interest' to both SIB and development capital. There are three sources of new capital for Contact:

a/ A capital raising from shareholders (which was done in 12th March 2021 during FY2021 ostensibly for Tauhara, but also to fund further developments like the Geofutures project).
b/ Retained operational cashflows.
c/ Borrowing from banks or setting up listed company bonds.

Now if Contact has already raised more capital than will probably be needed to build Tauhara, why is all of this interest ($8m over FY2021 and $19m over FY2022, refer AR2022 p113) being capitalised into Tauhara? Could you not equally well argue that due to the generous dividend payments being made by Contact Energy (dividends exceed NPAT), that really Contact is 'borrowing to pay their dividends'? That would mean that none of these interest charges should be capitalised at all (but interest expense would increase)?

SNOOPY

Snoopy

10-09-2022, 09:06 PM

The main point that I find baffling is the apportioning of 'capitalised interest' to both SIB and development capital.

Next we move to page 104 of AR2022 and the cashflow statement. There we see 'interest paid' was $28m (over FY2022) compared with $43m (over FY2021). If we now go to section B5 in the notes titled 'Net Interest Expense', then we can see how these two numbers are arrived at:

FY2022FY2021

Interest Expense on Borrowings($48m)($52m)

add back Interest Capitalised$19m$8m

add back Interest Income$0m$1m

equals Net Interest Paid (Cashflow Basis)$29m$43m

OK the figure for FY2022 is $1m out. But I am fairly sure this is but a rounding error (it is certainly within the error bounds of reporting on differences in whole number figures).

So far so good. But is adjusting for 'capitalised interest' the only difference between 'capital expenditure' and 'cashflow capital expenditure'? I wish I knew the answer!

Now we move to Slide 24 of PR2021. There we see growth investment of $76m, Stay In Business capital expenditure of $75m (does that mean $1m in growth capital expenditure, and $75m in existing installation capital expenditure?) and 'cash' SIB capital expenditure of $61m.

Adding back $8m of 'capitalised interest' (which I guess means I am assuming that all of that 'capitalised interest' refers to SIB capital) to that last figure gets us to:

$61m + $8m = $69m

Now $69m is some way short of $75m. This would suggest that 'capitalised interest' is not the only factor to consider when moving between 'capital expenditure' and 'cash capital expenditure'. Hmmm,,,,,,

SNOOPY

Snoopy

11-09-2022, 09:16 PM

Now we move to Slide 24 of PR2021. There we see growth investment of $76m, Stay In Business capital expenditure of $75m (does that mean $1m in growth capital expenditure, and $75m in existing installation capital expenditure?) and 'cash' SIB capital expenditure of $61m.

Adding back $8m of 'capitalised interest' (which I guess means I am assuming that all of that 'capitalised interest' refers to SIB capital) to that last figure gets us to:

$61m + $8m = $69m

Now $69m is some way short of $75m. This would suggest that 'capitalised interest' is not the only factor to consider when moving between 'capital expenditure' and 'cash capital expenditure'. Hmmm,,,,,,

Breakthrough?

From slide 21 of PR2021, we learn that Contact have spent $7m on 'Capitalised Revenue Incentives' over FY2021. My understanding of this, from a retail perspective, is this. A Contact Energy representative knocks on your door and asks you to 'switch to them', while offering $20 off each of your bills for the ensuing two years. Despite them offering you a discount on the spot, the accounting treatment of this is to match the discount to the time period that the associated bill is issued. This means any customer discount offered on the Contact books is capitalised as a debt called a 'capitalised revenue incentive'.

The whole purpose of these 'capitalised revenue incentives' is to lock in future revenue streams. For example, customers can be sold 'as a block' between gentailers. So buying a 'block of customers' is akin to investing in a 'hard asset', in that:

a/ Revenue is generated in both cases AND
b/ Capital is required to purchase either asset class..

Thus in this way, securing customers can be thought of as a class of 'capital expenditure' for Contact to 'Stay In Business', with the to-ing and fro-ing of customers in a dynamic and competitive market.

Now if we add up for FY2021:

SIB Capital Expenditure (cash) + Capitalised Interest + Capitalised Revenue Incentive = $61m + $8m + $7m = $76m

If we consider the error bounds of the rounded whole numbers we are adding, this is a very close match for the $75m SIB capex (accounting) figure for FY2021.

Have I just solved the problem of bridging the gap between SIB Capital Expenditure (cash) and SIB Capital Expenditure (accounting)?
Or have I just written the biggest load of drivel that has appeared on this forum this month?

SNOOPY

P.S. Using the same technique for FY2022, I get:

SIB Capital Expenditure (cash) + Capitalised Interest + Capitalised Revenue Incentive = $75m + $19m + $5m = $99m

$99m is therefore the figure for SIB Capital Expenditure (accounting) for FY2022 that was not disclosed. But this assumes that all of the capitalised interest was stacked up against SIB Capital Expenditure and not growth Capital Expenditure in Tauhara.

Muse

11-09-2022, 11:14 PM

Breakthrough?

From slide 21 of PR2021, we learn that Contact have spent $7m on 'Capitalised Revenue Incentives' over FY2021. My understanding of this, from a retail perspective, is this. A Contact Energy representative knocks on your door and asks you to 'switch to them', while offering $20 off each of your bills for the ensuing two years. Despite them offering you a discount on the spot, the accounting treatment of this is to match the discount to the time period that the associated bill is issued. This means any customer discount offered on the Contact books is capitalised as a debt called a 'capitalised revenue incentive'.

The whole purpose of these 'capitalised revenue incentives' is to lock in future revenue streams. For example, customers can be sold 'as a block' between gentailers. So buying a 'block of customers' is akin to investing in a 'hard asset', in that:

a/ Revenue is generated in both cases AND
b/ Capital is required to purchase either asset class..

Thus in this way, securing customers can be thought of as a class of 'capital expenditure' for Contact to 'Stay In Business', with the to-ing and fro-ing of customers in a dynamic and competitive market.

Now if we add up for FY2021:

SIB Capital Expenditure (cash) + Capitalised Interest + Capitalised Revenue Incentive = $61m + $8m + $7m = $76m

If we consider the error bounds of the rounded whole numbers we are adding, this is a very close match for the $75m SIB capex (accounting) figure for FY2021.

Have I just solved the problem of bridging the gap between SIB Capital Expenditure (cash) and SIB Capital Expenditure (accounting)?
Or have I just written the biggest load of drivel that has appeared on this forum this month?

SNOOPY

P.S. Using the same technique for FY2022, I get:

SIB Capital Expenditure (cash) + Capitalised Interest + Capitalised Revenue Incentive = $75m + $19m + $5m = $99m

$99m is therefore the figure for SIB Capital Expenditure (accounting) for FY2022 that was not disclosed. But this assumes that all of the capitalised interest was stacked up against SIB Capital Expenditure and not growth Capital Expenditure in Tauhara.

hey snoopy - why don't you just email Contacts investor relations team and ask them to give you a rec'y? I've had awesome experiences with accounting/technical/reconciliation queries and must now have direct contact with ~7 listed coy CFOs or financial controllers. You pay for the priviledge as a shareholder of having an investor relations function so you may as well use it

blackie

12-09-2022, 05:29 PM

crikey Snoop, good effort. you have left me feeling........ well, inadequate.
please don't tell me you can back a truck and trailer unit. give me somethin' :eek2:

Snoopy

12-09-2022, 08:06 PM

crikey Snoop, good effort. you have left me feeling........ well, inadequate.

It comes with being 'dogged' blackie. Getting that snout right into the paperwork and sniffing around until you find what you want. (O.K. I probably couldn't do it without the pdf search function. But there you go.)

please don't tell me you can back a truck and trailer unit. give me somethin' :eek2:

You got me there Blackie. Christchurch has a wizard. And if votes fall the right way, he might even be mayor next month. But you guiys who can back a truck and trailer unit..... That is where the real magic is.

SNOOPY

Snoopy

12-09-2022, 08:37 PM

hey snoopy - why don't you just email Contacts investor relations team and ask them to give you a rec'y? I've had awesome experiences with accounting/technical/reconciliation queries and must now have direct contact with ~7 listed coy CFOs or financial controllers. You pay for the privilege as a shareholder of having an investor relations function so you may as well use it

I have had mixed results from this technique in the past. My tactic was to ask a relatively simple question fired off to 'investor relations' first. Then once you know who is replying to you, follow up with a more complex follow up question. The problem I have found is if your follow up question is 'too hard' then they go quiet on you. Other times the 'percy approach', ringing a top guy straight away is the go. I tend to find that works better for medium sized companies than top ten monoliths though. But thanks for the suggestion. We will see. But in the meantime my snout is still on the trail...

SNOOPY

Snoopy

12-09-2022, 09:57 PM

If we add up for FY2021:

SIB Capital Expenditure (cash) + Capitalised Interest + Capitalised Revenue Incentive = $61m + $8m + $7m = $76m

If we consider the error bounds of the rounded whole numbers we are adding, this is a very close match for the $75m SIB capex (accounting) figure for FY2021.

Have I just solved the problem of bridging the gap between SIB Capital Expenditure (cash) and SIB Capital Expenditure (accounting)?
Or have I just written the biggest load of drivel that has appeared on this forum this month?

Back to PR2021 and slide 5
"During the year, Contact committed to the construction of the new 152MW Tauhara geothermal development, with the total capital investment totalling $177m for the financial year."

Immediately opposite that statement we learn that SIB Capital Expenditure (cash) was $61m, Growth capital Expenditure (cash) was $76m and Strategic Investments (cash) swallowed up $40m. Add up those three figures and I get:

$61m + $76m + $40m = $177m.

I take it from this that the 'total capital investment during the year' referred to in my quote above actually means 'total capital investment during the year (cash)'. This is 'sloppy stuff' considering everything I have mentioned so far is on the same slide.

Now go down in the same document to slide 24. Look at the bar graph on 'Sources and Uses of Cash'. There you will see $76m of 'Growth Investment' (purple) and of $40m of strategic investment (black). Both of these are part of 'capital expenditure totalling $177m'. But where is the $61m of SIB capital in that 'use of cash' column? It isn't part of 'debt reduction', nor part of 'Dividends Paid'. So by elimination it must be part of 'Cash Movement' of $106m. Why it is not shown as the separate 'SIB capital' that it is, I am not sure.

Using the same technique for FY2022, I get:

SIB Capital Expenditure (cash) + Capitalised Interest + Capitalised Revenue Incentive = $75m + $19m + $5m = $99m

$99m is therefore the figure for SIB Capital Expenditure (accounting) for FY2022 that was not disclosed. But this assumes that all of the capitalised interest was stacked up against SIB Capital Expenditure and not growth Capital Expenditure in Tauhara.

Next we look at the 'Uses of cash' column' for FY2022, found in PR2022 on slide 25. Now we have a much larger 'purple section' of the column amounting to $261m of 'capital investments' (which presumably includes Tauhara), $3m of unspecified 'Stategic Investments and Acquisitions'. 'Cash movement' seems to be a mere $18m (not enough to include SIB capital). So I have to conclude that SIB capital (cash) for FY2022 of $75m must be included in the 'big purple total' of $261m, (in sharp contrast to FY2021 when it wasn't).

Just to make things worse, I have noticed that the 'cashflow uses column' shows dividends paid totalling $272m, when it is quite clear from the cashflow statement that the dividends paid over the year amounted to only $242m. There is only one thing to be done when faced with this many inconsistencies late into the evening. Head for the kennel. Good night!

SNOOPY

Snoopy

13-09-2022, 12:45 PM

Back on the horse twice this month, now the FY2022 result has been released.

This 'scenario analysis' is not an historical record of what happened. Instead it answers the question, what would happen if current dividend policy acted on the historical results of previous years. The purpose of this is to get a measure of how future results might change, if the weather events of the previous four years were superimposed on today's investment policy.

For this analysis I am using the most recent dividend policy (FY2021) of paying 80-100% of cashflows. For modelling purposes I will 'split things down the middle' and assume 90% of free cashflows are paid out. Contact have also said they will base their level on dividend payments around the last four years of results So for the purpose of this exercise, my timeframe is from FY2019 to FY2022 inclusive.

FY2019
FY2020
FY2021
FY2022

Cashflows from Operating Activities (1,2)
$466m + $85m
$390m+$85m
$475m+$85m
$428m+$85m

less Stay in Business CAPEX
($60m)
($52m)
($75m)
($85m) (Note 5)

less Net Interest Expense
($70m)
($55m)
($50m)
($36m)

equals Operating Free Cashflow
$380m
$421m
$368m
$392m

Default

Operating Free Cashflow (OFC) x 80%
$304m
$337m
$294m
$314m

Modelled Dividend per Share OFC80% (based on 808m shares on issue (3))
38cps
42cps
36cps
39cps

Operating Free Cashflow (OFC) x 90%
$342m
$379m
$331m
$353m

Modelled Dividend per Share OFC90% (based on 808m shares on issue (3))
42cps
47cps
41cps
44cps

Default
EBITDAF-DA-I-T (Normalised NPAT) (4)
$175m +$45m
$127m + $45m
$183m + $45m
$172m + $45m

Normalised forecast 'eps' (based on 808m shares on issue)
27.2cps
21.3cps
28.2cps
26.9cps

Notes

(1) From slide 6 of PR2020: "Projected EBITDAF uplift of ~$85m p.a. at wholesale price of $80/MWh" on commissioning of Tauhara.

(2) The definition of 'Operating Cashflows' has slightly changed between FY2019 and FY2020. This has affected the 'Operating Cashflow' figure that I have used, which from FY2020 is different to that in the latter cashflow statements. In AR2019 the 'interest paid' is reported in 'Financing cashflows' and the 'interest earned' is reported under 'Investing cashflows'. By contrast both are reported in 'Operating Cashflows' in AR2020. For consistency I am using the earlier definition of cashflows in the above table, with no interest charges deducted or added.

(2a) FY2020 'Operating Cashflow' for FY2019 is listed as $466m in AR2019 and $401m in AR2020. Why the difference? In FY2020 the FY2019 figure has been reduced by a net interest figure of $69m -$4m = $65m (Figures relating to FY2019). Applying the same adjustment logic to FY2020, where the net interest paid was $49m, this explains why 'Operating Cashflows' for FY2020 are listed as $390m in my table, but only $341m in the FY2020 Integrated Report.

(2b) FY2021 'Operating Cashflow' adjustment. The net interest figure paid over FY2021 was $43m. This explains why 'Operating Cashflows' for FY2021 are listed as $475m in my table, but only $432m in the FY2021 Integrated Report.

(2c) FY2022 'Operating Cashflow' adjustment. The net interest figure paid over FY2022 was $28m. This explains why 'Operating Cashflows' for FY2021 are listed as $428m in my table, but only $400m in the FY2021 Integrated Report.

(3) Following the capital raising completed on 12-03-2021, and the subsequent dividend paid on 30-03-2021 (with the DRP operating) on all shares issued (including those raised in the March 2021 capital raising), the number of shares on issue to jumped to 778,794,640 shares at the EOFY2022 balance date. I expect the DRP will further increase the number of shares on issue in the future, I predict at a rate of 2.5% per year (compounding). This will see the total number of shares after four years to increase as follows:

No.Shares

Year 0 (EOFY2022)778,794,640

Year 1798,264,506

Year 2818,221,119

Year 3838,676,647

Total/4 = Average808,489,228

(4) I shall assume with Tauhara commissioned Depreciation will go up by $14m per year (the same jump in depreciation that occurred when Te Mihi was commissioned). There is $180m of new incremental debt funding associated with the building of Tauhara. At a 5.0% borrowing rate, this will increase the annual interest bill by:

$180m x 0.05 = $9m

The projected NPAT increment as a result or Tauhara coming on stream is therefore:

0.72x ($85m -$14m -$9m) = $45m

(5) AR2022 Note A3 states Stay In Business (SIB) capital cashflow of $75m over FY2022. I have applied a 20% surcharge on this value to get an estimate of $85m for the total stay in business capital charge applicable to FY2022. Unlike previous years, overall SIB capex was not disclosed for FY2022 (except from AR2022 p60 'SIB Capex more than FY2021').

Tauhara Discount Factor for Future Earnings

This incremental increase in NPAT should perhaps be discounted back because it will not occur for two years time, at the point where Tauhara comes on line. For future discounting of profits, I use a 5.0% discount rate, which equates to the long term Gross Yield I am prepared to accept.

1/(1.05)^2 = 0.9070

$45m x 0.9070 = $41m

I feel like I have been down a bit of a rabbit hole scratching up detail over the last few days. So time to put it into context and remind ourselves what the end goal of this exercise is. One word - 'Dividend Yield' (O.K., I know that is two words but you get the idea).

I am re-doing this exercise because I have noticed in AR2022 p60 that the declared multi-year 'operating free cashflow' lists different numbers to what I have been using in my quoted analysis (above). Why is this? Because of an accounting rule change that has affected the cashflow statement between FY2019 and FY2020.

Over and prior to 2019:
a/ the 'Interest paid' was reported in 'Financing cashflows' AND
b/ the 'Interest earned' is reported under 'Investing cashflows'.

By contrast, both 'interest paid' and 'interest earned' are now reported in 'Operating Cashflows' (from FY2020 onwards). Since dividends are directly derived from 'Operating Free Cashflows', this change makes a considerable difference to the level of dividends forecast to be paid. How much is a 'considerable difference'? That is exactly what this post is all about (as the first step in that 'finding out' process at least).

Once again I need to remind people that this 'scenario analysis' is not an historical record of what happened. Instead it answers the question:
"What would happen if current dividend policy acted on the historical operational results of previous years?"
The purpose of this exercise is to get a measure of how future results might change, if the 'weather and market feeder events'` of the previous four years were superimposed on today's dividend policy.

For this analysis I am using the most recent dividend policy (FY2021) of paying 80-100% of cashflows. I am also assuming that Tauhara is already built and operational. For modelling purposes, I will 'split things down the middle' and assume 90% of free cashflows are paid out. And I will have a second 'bite of the cherry', detailing what would happen if only 80% of earnings were paid out. Contact have said they will base their level on dividend payments around the last four years of results. So for the purpose of this exercise, my time-frame is from FY2019 to FY2022 inclusive.

FY2019
FY2020
FY2021
FY2022

Cashflows from Operating Activities (1,2)
$401m+$85m
$341m+$85m
$432m+$85m
$400m+$85m

less Stay in Business CAPEX
($60m)
($52m)
($75m)
($85m) (Note 4)

less Net Interest Expense
($70m)
($55m)
($50m)
($36m)

equals Operating Free Cashflow
$356m
$319m
$392m
$364m

Operating Free Cashflow (OFC) x 80%
$285m
$255m
$314m
$291m

Modelled Dividend per Share OFC80% (based on 808m shares on issue (2))
35cps
32cps
39cps
36cps

Operating Free Cashflow (OFC) x 90%
$320m
$287m
$353m
$328m

Modelled Dividend per Share OFC90% (based on 808m shares on issue (2))
40cps
36cps
44cps
41cps

EBITDAF-DA-I-T (Normalised NPAT) (3)
$175m+$45m
$127m+$45m
$183m+$45m
$172m+$45m

Normalised NPAT forecast 'eps' (based on 808m shares on issue)
27.2cps
21.3cps
28.2cps
26.9cps

Notes

(1) From slide 6 of PR2020: "Projected EBITDAF uplift of ~$85m p.a. at wholesale price of $80/MWh" on commissioning of Tauhara.

(2) Following the capital raising completed on 12-03-2021, and the subsequent dividends paid from 30-03-2021 (with the DRP operating) on all shares issued (including those raised in the March 2021 capital raising), the number of shares on issue has jumped to 778,794,640 shares (as at the EOFY2022 balance date). I expect the DRP will further increase the number of shares on issue in the future, I predict at a rate of 2.5% per year (compounding). This will see the total number of shares after four years to increase as follows:

No.Shares

Year 0 (EOFY2022)778,794,640

Year 1798,264,506

Year 2818,221,119

Year 3838,676,647

Total/4 = Average808,489,228

(3) I shall assume with Tauhara commissioned, depreciation will go up by $14m per year (the same jump in depreciation that occurred when Te Mihi was commissioned). There is $180m of new incremental debt funding associated with the building of Tauhara. At a 5.0% borrowing rate, this will increase the annual interest bill by:

$180m x 0.05 = $9m

The projected NPAT increment as a result or Tauhara coming on stream is therefore:

0.72x ($85m -$14m -$9m) = $45m

(4) AR2022 Note A3 states 'Stay In Business' (SIB) capital (cash) of $75m was spent over FY2022. I have applied a 20% surcharge on this value to get an estimate of $85m for the total stay in business capital charge applicable to FY2022. Unlike previous years, overall SIB capex was not disclosed for FY2022, only the 'cash' spend, (except from AR2022 p60 'SIB Capex more than FY2021').

Double Check: Doing some 'reverse analysis' on the numbers we are given in AR2022. On p60 we are told that Operating Free Cashflow for FY2021 is $371m and for FY2022 is $325m.

Operating Cashflow - Net Interest - SIB Cashflow (Capex) = Operating Free Cashflow
FY2021:$432m - $50m - SIB Capex = $371m => SIB capex = $11m
FY2022:$400m - $36m - SIB Capex = $325m => SIB capex = $39m

Neither of those SIB Capex numbers Line up with what I know is correct for FY2021 and have estimated is correct for FY2022. So it looks like I have made a mistake somewhere?

SNOOPY

Snoopy

14-09-2022, 09:57 AM

Contact with their '80%-100% of Free Operating Cashflow' looks, in practice, to be paying dividends towards the bottom of their indicated range. I believe this is because the policy was based on 'averaged hydro-logical conditions'. If the inflows were above average (which they were in FY2019), then the dividend was not increased. My modelled future dividend scenario is that dividends will be capped at 37cps (This reflects the period after Tauhara has been commissioned remember). Over FY2022 dividends paid during that period amounted to 35cps.

I continue to use my model based on just the last four years of operations.

1/ The 'Scenario 'Dividend Per Share' and 'Scenario Earnings Per Share' columns (from my post 2245) represent a prediction of an ongoing dividend of 80% of free cash flow being paid into the foreseeable future, but now capped at 37cps.

The FY2021 and FY2022 actual dividend payments, under the same policy of paying out 80-100% of free cashflow, was 35cps. This is somewhat less than my four forecast scenarios where dividends are 37cps. But these scenarios reflect a future where Tauhara is operational which should provide an incremental boost to Contact's profitability. I do not consider the modelled dividend payout to be unrepresentatively high, once Tauhara is up and running.

2/ The (A) - (B) difference column, if negative, represents the amount of the projected dividend not covered by imputation credits. This is important, because a dividend paid without imputation credits is -in accounting terms-, equivalent to giving shareholders their own capital back (equal to the amount of the unimputed dividend) complete with a tax bill. This is generally bad for investors. It is necessary to make a negative adjustment to account for any expected tax to be paid on the unimputed dividend component (Column (D).
3/ The capital component of the dividend (Column C) is the portion of shareholder equity being returned to shareholders. This will need to be removed from the dividend return calculation. Because to pay it is to return to shareholders money on the balance sheet that they already have, so it isn't a shareholder benefit.
4/ The unimputed component tax bill (Column D), represents the income tax charged on share capital that is expected to be paid by the shareholder. A 28% tax bill from the value calculated in Column C is assumed. Note that if the (A)-(B) difference were to be positive then there would be no extra tax bill. That's because in such a year, the dividend would be 'fully imputed'.
5/ The final 'Difference Column' represents the 'effective' net dividend per share, adjusted for any extra tax obligation from paying tax on unimputed distributions.

Scenario Basis Financial Yeareps (A)Scenario dps (B)Difference (A)-(B)Divie Capital Component (C)Unimputed Tax Bill (D)Difference (B)-(C)-(D)

201927.3c37.0c-9.7c9.7c2.7c24.6c

202021.3c37.0c-15.7c15.7c4.4c16.9c

202128.2c37.0c-8.8c8.8c2.5c25.7c

202226.9c37.0c-10.1c10.1c2.8c24.1c

Total103.7c (E)148.0c (F)91.3c

Business Cycle Imputation Rate (E)/(F)70.07%

.

The expected average dividend per year, net of tax is therefore: 91.3 / 4 = 22.8cps (net)

Using a tax rate of 28c this is equivalent to a gross income of: 22.8cps /(1-0.28) = 31.7cps

Now we come to a critical point in this analysis - the choosing of an 'indicative interest rate' that allows us to value Contact on the basis of being an ongoing income stream.

Contact with their '80%-100% of Free Operating Cashflow' looks, in practice, to be paying dividends towards the bottom of their indicated range. I believe this is because the policy was based on 'averaged hydro-logical conditions'. If the inflows were above average (which they were in FY2019), then the dividend was not increased. My modelled future dividend scenario is that dividends will be capped at 37cps (This reflects the period after Tauhara has been commissioned remember). Over FY2022 dividends paid during that period amounted to 35cps.

I continue to use my model based on just the last four years of operations.

1/ The 'Scenario 'Dividend Per Share' and 'Scenario Earnings Per Share' columns (from my post 2313) represent a prediction of an ongoing dividend of 80% of free cash flow being paid into the foreseeable future, but now capped at 37cps.

The FY2021 and FY2022 actual dividend payments, under the same policy of paying out 80-100% of free cashflow, was 35cps. This is somewhat less than my forecast scenarios where most dividends are 37cps. But these scenarios reflect a future where Tauhara is operational which should provide an incremental boost to Contact's profitability. I do not consider the modelled dividend payout to be unrepresentatively high, once Tauhara is up and running, in normal years. However this scenario 'Iteration B' has highlighted to me that in the modelled year based on FY2020, a 37c annual dividend every year, might not be realistic. So I am reducing the dividend to 32cps for that one modelled year.

2/ The (A) - (B) difference column, if negative, represents the amount of the projected dividend not covered by imputation credits. This is important, because a dividend paid without imputation credits is -in accounting terms-, equivalent to giving shareholders their own capital back (equal to the amount of the unimputed dividend) complete with a tax bill. This is generally bad for investors. It is necessary to make a negative adjustment to account for any expected tax to be paid on the unimputed dividend component (Column (D).
3/ The capital component of the dividend (Column C) is the portion of shareholder equity being returned to shareholders. This will need to be removed from the dividend return calculation. Because to pay it is to return to shareholders money on the balance sheet that they already have, so it isn't a shareholder benefit.
4/ The unimputed component tax bill (Column D), represents the income tax charged on share capital that is expected to be paid by the shareholder. A 28% tax bill from the value calculated in Column C is assumed. Note that if the (A)-(B) difference were to be positive then there would be no extra tax bill. That's because in such a year, the dividend would be 'fully imputed'.
5/ The final 'Difference Column' represents the 'effective' net dividend per share, adjusted for any extra tax obligation from paying tax on unimputed distributions.

Scenario Basis Financial Yeareps (A)Scenario dps (B)Difference (A)-(B)Divie Capital Component (C)Unimputed Tax Bill (D)Difference (B)-(C)-(D)

201927.3c37.0c-9.7c9.7c2.7c24.6c

202021.3c32.0c-10.7c10.7c3.0c18.3c

202128.2c37.0c-8.8c8.8c2.5c25.7c

202226.9c37.0c-10.1c10.1c2.8c24.1c

Total103.7c (E)143.0c (F)92.7c

Business Cycle Imputation Rate (E)/(F)72.52%

.

The expected average dividend per year, net of tax is therefore: 92.7 / 4 = 23.2cps (net)

Using a tax rate of 28c this is equivalent to a gross income of: 23.2cps /(1-0.28) = 32.2cps

Observant readers will note that despite the slightly reduced dividends I am modelling, average earnings have increased. How is that possible? It is because the reduced dividends were more than offset by the lower tax paid on the capital return part of the dividend.

Now we come to a critical point in this analysis - the choosing of an 'indicative interest rate' that allows us to value Contact on the basis of being an ongoing income stream.

SNOOPY

Snoopy

14-09-2022, 01:23 PM

The expected average dividend per year, net of tax is therefore: 92.7 / 4 = 23.2cps (net)

Using a tax rate of 28c this is equivalent to a gross income of: 23.2cps /(1-0.28) = 32.2cps

Observant readers will note that despite the slightly reduced dividends I am modelling, average earnings have increased. How is that possible? It is because the reduced dividends were more than offset by the lower tax paid on the capital return part of the dividend.

Now we come to a critical point in this analysis - the choosing of an 'indicative interest rate' that allows us to value Contact on the basis of being an ongoing income stream.

There are two parts to this valuation of Contact Energy shares:

1/ The dividend yield generation capacity of existing assets.
2/ The embedded build capability reflecting the 'earning capability of future assets' that can be built without raising further shareholder capital.

It is only part 1 of this valuation that I am tackling now.

------------------------

If we assume that a business cycle investment 'gross return' of 5.0% is required, then this equates to a CEN share price of no more than:

32.2c /0.05 = $6.44

So $6.44 is therefore 'fair value' on a 'whole of business cycle' dividend basis, including a commissioned Tauhara. However, Tauhara will not be completed for two years. That means we need to discount the incremental portion earnings due from Tauhara by a suitable 'Time Value of Money' factor.

Modelled FY2019
Modelled FY2020
Modelled FY2021
Modelled FY2022
Modelled Average

Normalised Operational NPAT
$175m+$45m
$127m+$45m
$183m+$45m
$172m+$45m
$164m+$45m

The estimated incremental Tauhara profit included in each of the above figures is $45m. So on a 'modelled average' basis, we can say the $45m from Tauhara is delivering a proportionate: $45m/$209m = 21.5% of profit (meaning 78.5% of profit is from non-Tauhara assets).

For future discounting of Tauhara profits two years out, I use a 5.0% discount rate, (which equates to the long term Gross Yield I am prepared to accept: 1/(1.05)^2 = 0.9070

My fair value income yield valuation for Contact Energy, apportioned for the incomplete Tauhara is calculated as follows.

(Non-Tauhara Apportioned Capitalised Dividend) + (Tauhara Apportioned Capitalised Dividend)
=(0.785)($6.44) + (0.215)($6.44)(0.9070) = $6.31

SNOOPY

Snoopy

14-09-2022, 03:22 PM

My fair value income yield valuation for Contact Energy, apportioned for the incomplete Tauhara is calculated as follows.

(Non-Tauhara Apportioned Capitalised Dividend) + (Tauhara Apportioned Capitalised Dividend)
=(0.785)($6.44) + (0.215)($6.44)(0.9070) = $6.31

There are two parts to this valuation of Contact Energy shares:

1/ The dividend yield generation capacity of existing assets (quoted above).
2/ The embedded build capability reflecting the 'earning capability of future assets' that can be built without raising further shareholder capital.

It is part 2 of this valuation that I am tackling now.

------------------------

Contact Energy generation assets that have a significant unbooked premium on their book value are the hydro assets at Clyde and Roxburgh. We can estimate the quantum of this from similar increases in hydro station value that were booked by competitor Mercury Energy (see post 1878). The rising value of future cashflows, that increase the relative worth of long lived legacy power generation assets is an additional 'return' - for which I have previously coined the term 'thin air capital'. That sounds ethereal, and is, to the extent that this 'capital' appears solely on the expectation of power prices rising. However, although the short term power prices at the wholesale level go up and down, long term power prices go up and up. So in practice I have never seen any of the Mercury Energy declared new 'thin air capital' on their hydro generation assets ever vanish, even if theoretically it could (This is why I like the name 'thin air capital', because it carries a juxtaposed connotation of 'fragile permanence').

The 'thin air' capital growth for Mercury hydro assets is shown below. Both Mercury and Contact operate in the same electricity market. That is why I consider the thin air capital accumulated by Mercury as an indicative factor to use for the thin air capital accumulated (but not recognised) by Contact management over that same period. Information in the table below is derived from posts 1450 and 1456 in the Mercury thread.

Mercury Energy
Reval. Hydro & Thermal Assets ($m)
Reval. Geothermal & Other Generation Assets ($m)
Reval. Wind Generation Assets ($m)
Total Revalued Generation Assets

2015
355
142
N.A.
497

2016
82
55
N.A.
137

2017
0
52
N.A.
52

2018
0
55
N.A.
55

2019[/
151
99
N.A.
250

2020
253
43
N.A.
296

2021
550
388
N.A.
938

2022
139
1
153
293

Total
1,530

That $1,530m of thin air incremental capital raised was based on a total hydro generating capacity of 1059MW (Post 1450, Mercury Thread). The total Contact Energy hydro electric generation capacity is 784MW (my post 1514). So I can determine my 'best guess' at the thin air capital accumulated by Contact Energy subsequent to the FY2014 balance date by ratio:

$1,530m x 784MW/1059MW = $1,133m

I have decided to change my asset increment valuation approach from previous years. Revalued assets, according to accounting rules attract an associated tax liability, on a deferred basis. Contact Energy are not revaluing their assets as is their policy. But if they did, they would incur such a deferred tax liability amounting to 28% of the revaluation amount, (which may never be crystallised). Nevertheless I am going to use the revaluation amount net of any deferred tax to be consistent with the accounts of competitor Mercury Energy, which does revalue assets and does follow the revaluation and deferred tax rules.

$1,133m (Asset Revaluation) = $816m (Net Asset Revaluation) + $317m (Deferred tax liability)

New Capital projects are funded by a combination of debt and equity. If we take a 54% equity ratio going forwards as 'acceptable' (see post 2205, 54% being a typical value pre the March 2021 capital raising for Tauhara), then this $816m of new 'thin air' equity could in theory fund capital projects to the tune of:

$816m / 0.54 = $1,511m

Take the project capital needed to complete Tauhara out of that total, and new incremental project capital is reduced to:

$1,511m - $818m = $693m.

What sort of capacity geothermal power station might $693m of cpital build?
Now 693/818= 0.847. And 168MW x 0.847 = 142MW. Theoretically, add in a new companion bond program, and it means I can see equity capital for another Tauhara sized field geothermal station (actually a geothermal station 84.7% the size) as being available right now.

A new 142MW power station would lift operational generating capacity by

(142MW x 0.94) / (403MW + 527MW) = +14.4%

(refer post 2206 for method)

This raises my 'fair value' of Contact Energy, based on my steady state income valuation, by 14.4%

$6.31 x 1.144 = $7.22

With CEN trading on the market at $7.85 as I write this, I consider it 8.7% overvalued.

SNOOPY

discl: holder

Snoopy

15-09-2022, 09:38 AM

On the release of the FY2022 results, CEO Mike Fuge had this to say on the future of the power industry.

---------------------

Mr Fuge said Contact has been saying for some time that the role of thermal assets will change from running baseload to providing risk management support; backed by fixed insurance-style payments.
“Contracts like this one show the merits of Thermal Co – an industry-wide entity that could provide the risk management support the market needs, at the lowest cost with the lowest carbon emissions while new renewable generation is built.” This arrangement with Meridian (1) demonstrates the efficiency of the market and will reduce the use of coal.

Contact also announced that its 44MW Te Rapa power station will close in June 2023. The closure of this station will ultimately reduce Contact’s scope 1 and 2 greenhouse gas emissions by ~20 percent per annum or 200 000 tons per annum - the equivalent of taking 44,000 vehicles off the road.

(1) Fuge is talking about the deal between Genesis and Meridian where Meridan agrees to pay Genesis a fixed sum to keep Huntly 'at the ready' should soutern lake levels drop.

----------------------

Fuge doesn't put it in these exact words. But my reading of this quote is that Fuge is putting forward the idea of 'defacto nationalisation' of all the thermal power stations in the country under the 'Thermalco' banner either:

a/ As a prelude to Onslow being completed, OR
b/ To allow Thermalco to do the 'top up job' that Onslow would be doing if it existed, and so pushing Onslow out further into the future. The secret hope being that once the country realises what an economically efficient job an 'independent' Theremalco is doing, and while more renewable generation is built in the interim, then we will not need Onslow (Let's face it, none of the gentailers want Onslow to be built in their own ideal fully commercial world).

The interesting thing about this announcement was that it was coupled with Contact's firm plans to close their own Te Rapa co-generation plant. That means that should Thermalco come into being, it will consist almost entirely of Huntly and one or two rag tag peaker plants (As an example, I think Todd's still has one in New Plymouth). Fuge wants Huntly removed from 'commercial control'. IOW he wants it taken off Genesis Energy.

Anyone like to comment as to whether I am interpreting what Fuge has stated correctly?

SNOOPY

xafalcon

15-09-2022, 11:39 AM

When Lake Onslow is confirmed, that will define the remaining useful life of Huntly. Genesis is unlikely to want to spend much capital maintaining an asset with a very defined lifespan. This represents a significant risk for electricity supply while Lake Onslow is being constructed. ThermalCo is one mechanism that could mitigate the risk. But I think its more likely that central government will include risk mitigation in the feasibility study. It may take the form of maintenance contributions during the construction and filling of Lake Onslow, or maybe a plant retirement payout once Lake Onslow is operational.

dibble

20-09-2022, 03:45 PM

It is somewhat of a paradox to receive an email from CEN to say my electricity will cost "a bit more", where "bit" is a lot more than the "2-3%" general RBNZ inflation target. Guaranteed bigger charges, possible bigger dividend....Moan/rejoice... buy more shares/change supplier, ignore/send hate mail to russia etc etc.

RTM

21-09-2022, 11:52 AM

Wright

21-09-2022, 12:10 PM

You can thank the Govt for that, they are phasing out the low fixed rate tarif, its goes up to $1.80 by 2026 then removed entirely.

https://www.mbie.govt.nz/building-and-energy/energy-and-natural-resources/energy-consultations-and-reviews/electricity-price/phasing-out-low-fixed-charge-tariff-regulations/

kiora

28-09-2022, 10:47 AM

Lake Onslow?
Yeah ,no?
"From Boston to Waitoa: Fonterra trials 'world-first' organic battery"
https://www.nzherald.co.nz/business/from-boston-to-waitoa-fonterra-trials-world-first-organic-battery/XCIWMPZCSELUTPEUXRAAR3AVEQ/

Snoopy

30-09-2022, 03:14 PM

Theoretically, add in a new companion bond program, and it means I can see equity capital for another Tauhara sized field geothermal station (actually a geothermal station 84.7% the size) as being available right now.

A new 142MW power station would lift operational generating capacity by

(142MW x 0.94) / (403MW + 527MW) = +14.4%

(refer post 2206 for method)

This raises my 'fair value' of Contact Energy, based on my steady state income valuation, by 14.4%

$6.31 x 1.144 = $7.22

With CEN trading on the market at $7.85 as I write this, I consider it 8.7% overvalued.

The 'new bond' ('Green' no less) has arrived with a coupon rate of 5.82% per annum. (This reflects an issue margin of 1.30% per annum plus the Base Rate of 4.52% per annum.) Did I apply for any? No. For me to be interested the bond rate would have to have started with a '7'. So by my own standard these bonds are 7/5.82 = 1.20, so 20% overvalued. Still it is good to see other more risk tolerant than me 'taking that bond risk'.

Meanwhile the share price has come back to $7.45 today. So based on my $7.22 valuation, CEN is now 3% overvalued. Back to the bottom drawer for my Contact Energy shareholding. And back onto the top of the doghouse for me.

SNOOPY

mwri

17-11-2022, 01:52 PM

RMA reform crucial to Contact’s 5.7 TWh pipelineRMA reform crucial to Contact’s 5.7 TWh pipeline | Energy News (https://www.energynews.co.nz/news/energy-transition/130612/rma-reform-crucial-contacts-57-twh-pipeline)
Is the reformed RMA posing any real risk to the geothermal pipeline? If it follows the direction of the three waters reform could we see more red tape around the development of geothermal resources?

Simsee

21-11-2022, 05:55 PM

CEN bouncing round quite a bit last few days. Any idea why?

BlackPeter

21-11-2022, 06:09 PM

CEN bouncing round quite a bit last few days. Any idea why?

Always have a look at the bigger picture if the daily jitter makes you wonder ...

Here are the last 12 months with Bollinger bands.

14326

What exactly would you think was unusual the last few days? The daily jitter looks to me quite within the normal movement range ....

Simsee

21-11-2022, 06:18 PM

I’ve no intentions of selling, great share well run company it’s just unusual to see 2% + daily movements both up and down

Simsee

21-11-2022, 06:51 PM

Also interesting that nz down 3. Something vs asx up 2. Something??

see weed

21-11-2022, 10:30 PM

Also interesting that nz down 3. Something vs asx up 2. Something??
Good for day trading. I bought some today on close and will buy more on the dips.

BlackPeter

22-11-2022, 09:08 AM

I’ve no intentions of selling, great share well run company it’s just unusual to see 2% + daily movements both up and down

It is not ... just look at the 12 months chart. Ways larger daily movements around.

Snoopy

09-02-2023, 06:59 PM

As New Zealand does not have interconnection to other grids in different time zones our generation mix must take into account the daily demand profile and the intermittancy of solar and wind generation. We are already at the stage of wind generation causing our grid to reach load stability limits. Any additional solar without accompanying storage would only exacerbate that situation.

There is a solution, but one that none of the power companies are interested in. That is Pumped Storage Hydro. For every 1 MW of PSH the country can accept a further 2 MW of intermittant generation. PSH can pump water to storage when there is an excess of intermittant geneation, and generate withit when there is a deficit.

This thread is obviously the right place for this discussion as the two best sites for PSH are both in Contact's catchments. Lake Onslow could increase NZ's energy storage by 200% and provide 1200 MW, allowing up to a further 2400 MW of intermittant generation. This scheme would cost between $3.5 and $4 billion. The Neck between Hawea and Wanaka would only be 1/10 the size and cost around $400 million. Either of these would allow a huge increase in wind or solar and decrease the reliance on gas fired generation.

The above post from Jantar five years ago provides an interesting context for today's announcement from Contact Energy.

-------------------------

https://www.nzx.com/announcements/406412

"With around 300,000 solar panels, Kōwhai Park’s solar farm will be among the largest in New Zealand."

"The expected 150MW (or 170MWp) array will generate 290 GWh per year. This is equivalent to the annual demand of approximately 36,000 homes or approximately half of Christchurch’s domestic flights being converted to low-emission technologies."

"Contact Energy CEO Mike Fuge says they’re excited to announce this development partnership."

“We’ve committed to creating up to 380,000 megawatt hours of grid-scale solar generation by 2026, this project will deliver over half of that."

---------------------

Now who are Lightsource bp? The BP bit is that petroleum multinational that like to brand themselves 'Beyond Petroleum' these days. Lightsource is a British start up, founded in 2010 and now recognised as one of the largest solar developers in the world. "Lightsource bp" is a 50.50 joint venture between these two companies.

" “Lightsource bp has a strong international track record of successfully delivering utility scale solar projects, and with our partners at Contact Energy we look forward to working closely with Christchurch Airport on the development, construction and operation of Kōwhai Park,” says Adam Pegg, (LSbp’s Australia and New Zealand Country Manager"

https://lightsourcebp.com/about/

Contact is a 50/50 joint partner in developing this project, but has contracted to buy all of the power output from the solar array once built.

On the surface Kowhai Park looks like a good fit to be built on Christchurch Airport land. The airport is a power hungry operation and most of that power demand is in daylight. A perfect fit then, for having a large solar farm on the doorstep. But despite being a power hungry operation, I doubt if they would consume the equivalent power of 36,000 homes. However with all of those Fendalton housewives and househusbands on the doorstep, there will be plenty left over to power the morning tea party teapots and wash the starched table cloths afterwards.

The real question that remains unanswered in the Contact energy news release is the effect on grid stability, as I highlighted in bold in Jantars post. Could Kowhai Park be the domino that sees the Lake Onslow pumped storage project green lighted for sure? And hey presto, Contact are right on the doorstep to manage that! Very clever business tactics from Contact CEO Mike Fuge.

SNOOPY

fish

10-02-2023, 07:09 AM

kiora

10-02-2023, 08:29 AM

Snoopy have you considered that with solar you only need overnight storage-the neck could provide a lot more than this at 10% or less than the cost of Onslow .
Janitor could you tell us more?
Expert opinion on changing climate and solar dynamics much appreciated.

OR rather than pumped storage maybe better to use to make "Green Hydrogen" ?

"In time, the park will be home to green hydrogen generation and able to meet the needs of high users of energy, like vertical farms and data centres."

https://www.nzx.com/announcements/406412

Snoopy

10-02-2023, 01:18 PM

Snoopy have you considered that with solar you only need overnight storage.

Kōwhai Park’s solar farm will be rated at 150MW, with total energy produced forecast to be 290GWh/year. This implies a utilisation rate of:

290GWh/year / (0.15GW x 24h/d x 365d/year) = 22.0%

Now 22% works out at just 0.22 x 24 hours = equivalent to working at just 5.3 hours per day (equivalent work at maximum capacity). But that is an average based across all weathers and seasons. If the utilisation got to double that rate in Summer, then Kōwhai Park would be working at 10.6 hours per day, equivalent to a 44% utilisation rate.

So we might expect the energy produced in one day by Kōwhai Park on a summer day to be something like:

(150MW x 0.44) x 24h = 1,584MWh

Now Fish, here is what Jantar told us on 26th August 2022:

Onslow would not pump, or generate, based on the season, but rather it would do so based on the wholesale price. It is likely that it would be pumping when prices are less than around $50 per MW, and generating when prices are above $100 per MW. Because it can bid (for pumping) and offer (for generation) there would be a number of price bands, not a single price in each direction. It is likely that it would do both: Pumping overnight when prices are low, and generating during the day when prices are high on many days.

The above is telling me that principally, Onslow, despite its significant storage capacity, would be designed to operate as an overnight battery, first and foremost.

Clutha is a run of River scheme as the storage available at Clyde and Roxburgh is less than can be held for a single day. The median natural inflow at Clyde is 515 cumecs plus any water released from Hawea. IF there are:

a/ Median inflows, and minimum water being released from Hawea, AND
b/ Only releasing sufficient water from Clyde to meet the 286 cumecs from Roxburgh, AND
c/ Lake Dustan level was in the lower 1/4 of its 1 m operating range prior to starting,

THEN Clyde would be spilling water within 18 to 22 hours. This is the main definition of Run-of -River: Water reaching the top dam must be passed through within 24 hours.

Clyde is able to shut down for a few hours overnight when flows are low, and doesn't have to supply water to Roxburgh continuously as Roxburgh has around 6 hours of storage.

Working backwards through that, Roxburgh (with a maximum generation capability of 320MW, and a utilisation rate of 51.4%) is producing on average:

(320MW x 0.514) x 24h = 3948MWh of energy per day

This should be reasonably consistent all year round because summer river flows are driven by snowmelt on the Clutha river.

My conclusion is that, over summer, and treating Contact's Soiuth Island assets as one whole electricity system, Kōwhai Park could add 40% to Roxburgh's average daily output. But if that happened - which means water upstream at Clyde could be saved-, then even if the Clyde dam was at a low point (1/4 capacity), that means the Clyde dam would fill up within 18-22 hours. And the reason I am bringing the Clyde dam into this discussion is because the Clyde dam is the upstream power feed that will be supplying Onslow,

This means it is just as well we are only looking at the equivalent of a few hours of hydro storage displaced by Kōwhai Park solar. That's because we only have a few hours of available storage in that Clyde dam part of the Clutha river system that can be displaced.

SNOOPY

kiora

10-02-2023, 09:14 PM

Forget Onslow?
"There Kōwhai Park development made the airport a standout candidate for developing green hydrogen technology."
"The ability to produce renewable energy on-site is key for being able to eliminate carbon emissions from the aviation sector.

Secondly, as an atmospheric gas, hydrogen is extremely non-dense compared to traditional kerosene-based aviation fuel. Cooling and compressing hydrogen into a state that is usable on board aircraft is a challenge that Christchurch-based company Fabrum has been trying to address.

Fabrum’s Christopher Boyle says that being part of the consortium will “turbocharge” the transition and learning process for hydrogen tech."

“Apart from aviation, you have all the energy use cases here that makes Christchurch very interesting.”
https://www.nzherald.co.nz/travel/airbus-selects-new-zealand-as-launchpad-for-green-hydrogen-plane-tech-in-christchurch/O4CNYNWATBHGHHASZ6GEMM3PHA/

Sideshow Bob

13-02-2023, 08:38 AM

https://www.nzx.com/announcements/406544

Overview

New Zealand renewable energy company Contact Energy (‘Contact’) today released its interim financial results for the six months to 31 December 2022.

Contact CEO Mike Fuge said the financial performance in the first half of the FY23 financial year was reflective of soft short-term wholesale market conditions. Contact had made strong progress on delivering to its Contact26 strategy and was focused on leading New Zealand’s decarbonisation by connecting customers with its renewable development pipeline.

- Net loss of $7m reported after recognising an onerous contract provision of $120m ($86m after tax) following a review of the estimated available capacity of the Ahuroa Gas Storage Facility (AGS). Excluding AGS, underlying net profit was $79m.

- Underling EBITDAF (pre-AGS provision) decreased by $76m to $246m as a result of lower wholesale prices, lower renewable and thermal generation, increased operating costs to deliver on strategic growth priorities and inflationary conditions.

- Operating free cash flow decreased by $71m to $60m. Working capital continues to be elevated, with more gas and carbon in inventory.
- Resource consent gained to continue operating on the Wairākei geothermal field for the next 35 years, enabling planning to proceed on GeoFuture, a new station of up to 180MW at Te Mihi to replace Contact’s 64 year-old operations (Wairākei, 127MW).

- Selected by Christchurch Airport to deliver 170MWp (150MW) solar farm at Kōwhai Park through Contact’s joint venture with Lightsource bp.

- Market leading development pipeline expected to deliver up to 6TWh of new renewable electricity this decade, with 3.0TWh already consented.

- Te Rapa power station prepared for closure in June. On track to more than halve FY21 scope 1 and 2 carbon emissions by 2026.

- Strong endorsement of Contact’s refreshed retail offering in the past six months, with more than 20,000 new connections.

- Expanded ‘time of use’ offerings by introducing Dream Charge, enabling customers to charge their EVs at home at cheaper night rates and contributing to the decarbonisation of New Zealand.

- Supported customers by keeping price increases below inflation, despite sustained higher wholesale prices over the last 3 years.

- Launched a leading parental leave policy, ‘Growing your Whānau’, one of the most comprehensive, far-reaching parental leave policies in New Zealand.

Financial performance

Contact reported a net loss of $7m after recognising an onerous contract provision of $120m ($86m after tax) following a review of the estimated available storage capacity of AGS. This is a non-cash accounting adjustment to recognise the difference between the expected benefits received and the contracted schedule of payments. Underlying net profit of $79m was down $55m from a year ago on lower operating earnings (EBITDAF) and unfavourable movements to the fair value of financial instruments, partially offset by lower depreciation and lower tax on earnings against the prior year.

Underlying EBITDAF (pre-AGS provision) decreased by $76m to $246m, down 24 percent on the record result of 1H22, with lower wholesale prices, lower renewable and thermal generation and increased operating costs to deliver on strategic growth priorities and reflecting inflationary conditions.

Operating free cash flow for the period decreased from $131m to $60m, down 54% year-on-year on lower operating earnings, higher stay-in-business capital expenditure and higher cash tax paid on strong earnings in prior periods. This was partially offset by favourable working capital movements on a net basis. While lower than last year, working capital was still elevated as we held more gas and carbon in inventory.

The Board approved an interim dividend of 14 cents per share (imputed by up to 12 cents per share for qualifying shareholders) to be paid on 30 March 2023.
“Contact’s financial performance reflected the soft short-term wholesale market conditions experienced in the half year,” said Mr Fuge.

“We saw unprecedented hydro inflows which depressed market prices and saw greater price separation between the North and South Islands. We responded running less thermal generation and positioned our portfolio to benefit from expected improved market conditions in the second half.”

“Global energy and supply concerns continued to impact on commodity markets, with international energy prices holding at unprecedented levels, including coal. Domestic gas output remains constrained and readily accessible storage has reduced. These thermal fuel challenges continue to support the acceleration of our Contact26 strategy.”

Demand

In line with Contact’s decarbonisation focus, Mr Fuge said demand for renewable electricity from forward-thinking customers remained strong. Contact is focused on five key areas for demand growth, being large scale 24/7 data centres, industrial process heat, major industrial energy users, road transport and green chemicals.

“While still early days, we are excited about opportunities to work with major energy users pursuing their own decarbonisation strategies. Examples include working with NZ Steel to look at options around interruptibility and with the HW Richardson Group to assess a trial use of hydrogen for heavy transport. These have the potential to lead to large scale sources of new demand,” Mr Fuge said.

“With all new supply contracts, we are looking to build in demand response. This is of high value to Contact, our industrial customers and ultimately New Zealand. These initiatives will contribute to the decarbonisation of New Zealand whilst improving the security of supply at peak periods. We have been positively surprised by the customer appetite - from retail customers to large industrials - for demand response mechanisms to be packaged into new contracts,” said Mr Fuge.

“Significant new electricity demand is also now emerging in New Zealand, with new large scale 24/7 data centres. Hyperscale data centre projects announced by the likes of CDC, Microsoft and DCI are starting to come online and will see significant contributions to electricity demand over the next few years as each project stage reaches completion.”

Rio Tinto is looking to continue operating its unique low carbon smelter at Tiwai Point beyond 2024. Contact is engaging constructively and working toward new commercial arrangements.

Renewable development

Contact has been granted new consents to operate on the Wairākei geothermal field for the next 35 years. This enables it to proceed with replacing the 1950s-built Wairākei A and B power stations with a new station of up to 180MW at Te Mihi – the GeoFuture project. Contact is targeting a final investment decision around the end of this calendar year.

“This is an exciting milestone for Contact, moving our geothermal production off-river, and delivering better environmental outcomes,” said Mr Fuge.

“GeoFuture will be the third major development in five years from Contact’s world-class geothermal development pipeline, with Tauhara and Te Huka Unit 3 well on track for completion in 2023 and 2024 respectively. This is all low carbon, baseload renewable electricity that operates around the clock and is not weather reliant.”

Our joint venture partnership with global solar developer Lightsource bp has been selected by Christchurch Airport to deliver the first stage of its renewable energy precinct, Kōwhai Park – an estimated 170MWp solar farm. Subject to a final investment decision, construction is expected to begin in 2024.

Consenting for another 170MWp solar farm in the North Island is underway and the partnership has land access rights to potentially develop another ~60MWp of solar power.

Decarbonising our portfolio

Contact has announced the successful completion of carbon capture trials at its Te Huka geothermal power station. This gives Contact the option of either reinjecting carbon back into the geothermal reservoir, now a routine part of its Te Huka operation, or harvesting the C02 for commercial use. Contact is working with leading industrial gas supplier BOC, a Linde company, to assess the highest value commercial options for the use of the C02 being captured at its geothermal facilities. This includes pure C02 and combining C02 with hydrogen production for complementary derivative products (e.g. green chemicals).

“We are thrilled with these results. We will see the capture of 10,000 tons of greenhouse gas emissions per annum from Te Huka on an ongoing basis. This can be eliminated through reinjection or potentially used in commercial applications where these align to our decarbonisation strategy,” said Mr Fuge.

In addition, Contact is optimizing the flexibility it can achieve in its geothermal generation portfolio by shifting up to 11GWh of generation on the Wairākei field between the summer and winter periods in 2023. This reduces the need to run thermal generation.

The first half also saw Contact preparing for the planned closure of its 44MW Te Rapa power station in June 2023.

Retail

Mr Fuge said Contact’s retail business has continued with targeted growth in the first half of 2023, with customers on bundled packages up 13% on the prior period.
“We have seen connections increase by more than 20,000 in the half year. We are seeing significant growth in broadband, with connections up 30% on the prior period, and have introduced wireless broadband, providing yet another way for our customers to stay connected at home.”

Contact has expanded its time-of-use offerings, with its Dream Charge plan enabling customers to charge their EVs at home at cheaper night rates. This adds to Contact’s existing time-of-use offer, Good Nights, an initiative that’s proven popular with customers who can access three hours of free power every night from 9pm, shifting their load from peak evening times and thereby reducing the need for peak thermal generation, lowering carbon emissions.

In December, we were recognised at the NZ Compare Awards, winning Power Provider of the Year, Best Customer Support; Power and Best Bundled Plan. The awards recognise excellence and achievement in New Zealand’s broadband, energy and mobile sectos.

Outlook

Looking ahead, Mr Fuge said Contact remains committed to leading the decarbonisation of New Zealand.

“We are excited about the future. We have a clear strategy, strong balance sheet with supportive shareholders and a host of opportunities in front of us to lead the decarbonisation of the New Zealand economy over the next decade.”

winner69

13-02-2023, 08:52 AM

winner69

13-02-2023, 08:58 AM

No pay rise this time for those who rely on their dividend income

BlackPeter

13-02-2023, 09:03 AM

I not understand …… CEN report a LOSS and underlying performance pretty miserable lookingbasvwell

http://nzx-prod-s7fsd7f98s.s3-website-ap-southeast-2.amazonaws.com/attachments/CEN/406544/388317.pdf

Probably just because all these Gen Z girls spent all their money at Glassons ... and have no dollars left to pay the power bills :p ;

fish

13-02-2023, 09:45 AM

I not understand …… CEN report a LOSS and underlying performance pretty miserable lookingbasvwell

http://nzx-prod-s7fsd7f98s.s3-website-ap-southeast-2.amazonaws.com/attachments/CEN/406544/388317.pdf
I have felt uneasy about contact for sometime and been selling down .
A conference call is at 10 a.m where I suspect contact will try and tell us this is an aberration and we should look at the long-term future .
Cannot attend this but will be very interested how they try and sell this

Snoopy

13-02-2023, 03:25 PM

No pay rise this time for those who rely on their dividend income

Actually, for NZ shareholders, you aren't quite right about that

http://nzx-prod-s7fsd7f98s.s3-website-ap-southeast-2.amazonaws.com/attachments/CEN/406544/388317.pdf

"The Board approved an interim dividend of 14 cents per share (imputed by up to 12 cents per share for qualifying shareholders) to be paid on 30 March 2023."

Last year the equivalent dividend was 14cps (the same) but only imputed to 20%, not the full 28% if the dividend was fully imputed. So that is an imputation rate of 20/28= 71.4%.

If this years dividend has 12 of the 14c paid imputed that comes to 12/14= 85.7%. That means we shareholders do get a pay rise after tax, albeit a modest one.

SNOOPY

winner69

13-02-2023, 03:58 PM

Actually, for NZ shareholders, you aren't quite right about that

http://nzx-prod-s7fsd7f98s.s3-website-ap-southeast-2.amazonaws.com/attachments/CEN/406544/388317.pdf

"The Board approved an interim dividend of 14 cents per share (imputed by up to 12 cents per share for qualifying shareholders) to be paid on 30 March 2023."

Last year the equivalent dividend was 14cps (the same) but only imputed to 22%, not the full 28% if the dividend was fully imputed. So that is an imputation rate of 22/28= 78.6%.

If this years dividend has 12 of the 14c paid imputed that comes to 12/14= 85.7%. That means we shareholders do get a pay rise after tax, albeit a modest one.

SNOOPY

Technically correct Snoops but ……

Pay is what you get in the bank …and that’s going to be $1.94 less than less year according to my abacus but then it's an old worn abacus so no doubt you will correct

Things like imputation credits RWT, etc etc all get washed up in your tax return and lost with the other stuff

777

13-02-2023, 04:47 PM

see weed

13-02-2023, 05:19 PM

Contact left me with a little smile on close up 20c from the 11am low. Sometimes it is best to let them ride.

troyvdh

13-02-2023, 05:38 PM

Gee aint the sharemarket a funny thing.

winner69

13-02-2023, 06:13 PM

$ 0.18666667 is the gross dividend form the distribution notice to NZX

After tax you get 67% of it. Therefore banked is .18666667*.67=.1250666689

So per thousand shares that is $125.06

Last year the gross dividend was .17888889 . 67% of that was .11985555563

So per thousand shares that is $119.86

So increase this payment over last March payment is 4.347%

Using your numbers

Last year RWT is 5% of Gross so .1400 less RWT .0089 you got .1310 in the bank to pay groceries

This you get .1400 less RWT .0093 you will get .1307 in the bank for the groceries …less in my book for groceries costing heaps more

You never see imputation credits and RWT in the bank when divie paid …..even though it help you get a tax refund or reduce the tax bill

No doubt Snoopy will correct both of us.

Snow Leopard

13-02-2023, 07:25 PM

Snoopy

13-02-2023, 07:34 PM

Using your numbers

Last year RWT is 5% of Gross so .1400 less RWT .0089 you got .1310 in the bank to pay groceries

This you get .1400 less RWT .0093 you will get .1307 in the bank for the groceries …less in my book for groceries costing heaps more

You never see imputation credits and RWT in the bank when divie paid …..even though it help you get a tax refund or reduce the tax bill

No doubt Snoopy will correct both of us.

Winner, with the dividend declared you get is 14cps net (not gross).

The imputation credit must be added to that to get the gross figure. The higher the amount pf imputation the higher that gross income figure is for a fixed value 'net' dividend. If the dividend was 100% imputed (that means to the company tax rate of 28%) , then the gross dividend would be

14c / (1-0.28) = 19.44ec (fully imputed gross dividend), the imputed credit being: 19.444c - 14c = 5.444c

However, we know that the interim dividend was not fully imputed. It was imputed to 85.7% (FY2023) and 71.4% (FY2022). So the imputation credit for FY2023 is 0.857x5.444c = 4.666c, and the equivalent figure for FY2022 was 0.714x5.444c = 3.888c

This allows us to work out the gross interim dividend for the years under consideration as follows:

FY2022: 14c + 3.888c = 17.888c
FY2023: 14c + 4.666c = 18.666c

Now the company tax rate is 28%, but the individual tax rate reduction must add up to 33%. The difference between the company tax rate and the individual tax rate is adjusted by the taking away of resident withholding tax.

Gross Dividend
less Company Tax
less Resident Withholding Tax
equals Payment into Shareholder Bank Account

FY2022
17.888c
5.009c
0.894c
11.985c

FY2023
18.666c
5.226c
0.935c
12.506c

So you are right Winner pointing out that RWT will be higher in FY2023 than in FY2022. But that doesn't mean a shareholder will end up with less money in their bank account in FY2023. Because the higher deduction was taken off a higher base figure. Shareholders are better off in FY2023 by:

12.506c/11.985c = 1.0434 or 4.34%

SNOOPY

Snow Leopard

13-02-2023, 07:45 PM

...However, we know that the interim dividend was not fully imputed. It was imputed to 85.7% (FY2023) and 78.6% 71.4%(FY2022).
So the imputation credit for FY2023 is 0.857x5.444c = 4.666c, and the equivalent figure for FY2022 was 0.786x5.444c = 4.279c 3.8889c -- see NZX

This allows us to work out the gross interim dividend for the years under consideration as follows:

FY2022: 14c + 4.279c = 18.279c 17.8889c
FY2023: 14c + 4.666c = 18.666c

Now the company tax rate is 28%, but the individual tax rate reduction must add up to 33%. The difference between the company tax rate and the individual tax rate is adjusted by the taking away of resident withholding tax.

Gross Dividend
less Company Tax
less Resident Withholding Tax
equals Payment into Shareholder Bank Account

FY2022
18.279c
5.118c
0.914c
12.247c

FY2023
18.666c
5.226c
0.935c
12.506c

Paid was 11.9856c (2022) will be paid is 12.5067c (2023).

winner69

13-02-2023, 07:58 PM

Snoopy ….isn’t what’s paid into one’s bank account to pay for the groceries the Declared Dividend (14 cents) less RWT (calculated on Gross Dividend). Difficult to buy groceries with imputation credits …..countdown and others don’t accept them.

So on March 20th or whenever my abacus still says you are getting less in the bank this year because of the higher RWT deducted.

Pity there’s a difference between theoretical money and actual cash in the bank on pay day (dividend date)

My apologies for bring up the subject of no pay rise …..and now finding it’s a pay cut ….and the groceries are costing heaps more

Snow Leopard

13-02-2023, 08:10 PM

The last word from me:

14459

Don't argue with Snow Leopards :p

Snoopy

13-02-2023, 09:31 PM

Snoopy ….isn’t what’s paid into one’s bank account to pay for the groceries the Declared Dividend (14 cents) less RWT (calculated on Gross Dividend).

The above is only true if the company has not generated any imputation credits.

Difficult to buy groceries with imputation credits …..countdown and others don’t accept them.

Imputation credits are tax paid by the company under another name. The money from my Contact dividend has already had company tax, and an additional tax level adjusting RWT taken off it, before it gets deposited in my bank account. There is no more tax to pay by me! Countdown doesn't need to accept imputation credits because the money that lands in my bank account is fully tax paid. The imputation credit part of my tax statement is the income tax the company has paid on my behalf, and so never touches my bank account. As long as the IRD accepts my imputation credits then I am sweet!

So on March 20th or whenever my abacus still says you are getting less in the bank this year because of the higher RWT deducted.

My apologies for bring up the subject of no pay rise …..and now finding it’s a pay cut ….and the groceries are costing heaps more.

You are right about the groceries costing heaps more. You are wrong about me having less money to pay for them. I get 4.34% more money to pay with.

Pity there’s a difference between theoretical money and actual cash in the bank on pay day (dividend date)

Just because you don't see the imputation credits in your bank account doesn't mean they are theoretical. The IRD are happy to accept these so called 'theoretical tax constructs' (imputation credits) as tax paid on my behalf. Either that or I have just committed 30 years plus of tax fraud....(possible) but have never been caught (very unlikely).

SNOOPY

winner69

14-02-2023, 08:26 AM

Admitting defeat

winner69

14-02-2023, 08:34 AM

May as well admit defeat

Snoopy

14-02-2023, 09:50 AM

May as well admit defeat

Reminds me of a not so old African proverb.
"You won't learn much staring at de feet, and you may still trip over. Much better to keep de eye toward de Sky and move forward....."

SNOOPY

iceman

14-02-2023, 02:01 PM

Maybe some good news on Tiwai soon !! https://www.newstalkzb.co.nz/on-air/mike-hosking-breakfast/audio/mike-fuge-contact-energy-ceo-on-deal-reportedly-close-with-rio-tinto-over-tiwai-point/?fbclid=IwAR0Z5_WqUxQwlef38W54lHJBEyQWO14alXjgHJ2X W8YHuwar4qRb27hVpew

nztx

14-02-2023, 02:06 PM

777 is correct.

RWT on dividends is actually 33% of the gross [ see here (https://www.ird.govt.nz/income-tax/withholding-taxes/resident-withholding-tax-rwt/using-the-right-rwt-tax-rate) ] made up of:
1/ Imputation
2/ another amount to bring it 33% total.

No RWT on most dividends - Mr Leopard

RWT applies most commonly to Interest or similarly defined payments..

For Dividends, it is 'Dividend Withholding Tax" or in short DWT - mostly @ 5% on part of gross dividends that carry full imputation credits , and up to @ 33% of Gross distribution with reducing or No Imputation credit levels attached .. :)

Snow Leopard

14-02-2023, 02:50 PM

No RWT on most dividends - Mr Leopard

RWT applies most commonly to Interest or similarly defined payments..

For Dividends, it is 'Dividend Withholding Tax" or in short DWT - mostly @ 5% on part of gross dividends that carry full imputation credits , and up to @ 33% of Gross distribution with reducing or No Imputation credit levels attached .. :)

OK, I am calling it. You are a complete ignoramus.

Follow the link [to the IRD website!] I provided and read it

troyvdh

14-02-2023, 07:59 PM

I love it...finally folk are really starting to talk to each other ...other than trying to out wit each other with stats.
Dont get me wrong stats are vital...but the sharemarket is a weird beast.

BTW ...this whole debate is quite pathetic and meaningless....given whats going on up north...

Rawz

14-02-2023, 08:22 PM

Just glad I’m not the only one confused by the finer details of imputation credits etc lol

nztx

14-02-2023, 09:05 PM

OK, I am calling it. You are a complete ignoramus.

Follow the link [to the IRD website!] I provided and read it

Mr Leopard -- Inland Revenue even call the Withholding Tax "DWT - Dividend Withholding Tax" when
it is paid across to them too :)

The only tax they dont have facility for payment of is the mysterious "Complete Ignoramus Tax"
but who knows - it could be a tax spinner .. maybe they might like you to paint some spots on this one ;)

777

15-02-2023, 12:09 AM

Mr Leopard -- Inland Revenue even call the Withholding Tax "DWT - Dividend Withholding Tax" when
it is paid across to them too :)

The only tax they dont have facility for payment of is the mysterious "Complete Ignoramus Tax"
but who knows - it could be a tax spinner .. maybe they might like you to paint some spots on this one ;)

Straight from their website.

Dividend Payments

The RWT rate for dividend payments is 33%. The company paying the dividend will deduct this RWT before making the dividend payment to you.

You are only being a dickhead.

The IRD probably call the withholding tax on interest as IWT as well.

It makes no difference but your challenging of Snow Leopard is unnecessary. Childish in fact.

nztx

15-02-2023, 12:30 AM

Straight from their website.

Dividend Payments

The RWT rate for dividend payments is 33%. The company paying the dividend will deduct this RWT before making the dividend payment to you.

You are only being a dickhead.

The IRD probably call the withholding tax on interest as IWT as well.

It makes no difference but your challenging of Snow Leopard is unnecessary. Childish in fact.

https://www.ird.govt.nz/updates/news-folder/dividend-income-and-dividend-withholding-tax-dwt-details-in-myir

Display of dividend income and dividend withholding tax (DWT) details fixed

We have now fixed the issues affecting how dividend income and DWT details display in myIR, the Income API and the income tax return pre-pop in gateway services.

Customers will now see the correct amount of Resident Withholding Tax (RWT) and imputation credits. Customers with joint accounts will also see the correct allocation of their share of the dividend income and DWT.

Some customers with joint accounts may still see an incorrect allocation of their investment income. This is because both of the joint account holders gave the same IRD number to the bank or financial institution. These customers will need to give their correct IRD number to the bank or other financial institution.

see weed

28-02-2023, 11:52 AM

Another div due in a few weeks and ex div just over one week away on 9/3/23.

see weed

08-03-2023, 10:12 AM

Another div due in a few weeks and ex div just over one week away on 9/3/23.
Just another reminder for the div hunters, you have until 5pm today to buy in for the 14c div.

Muse

16-03-2023, 01:13 PM

BlackPeter

16-03-2023, 05:30 PM

Lake Onslow to cost $15.7bn (or in the words of a poster in the article below: "yeah right $15.7b x 2 more likely") and gov proceeding to next stage of feasibility planning

https://www.interest.co.nz/public-policy/120351/government-puts-massive-price-tag-potential-lake-onslow-pumped-hydro-scheme

Think BIG project. 15.7 bn are a bit more than $3000 per head of population in NZ, and with the inevitable cost rises at least $5000 ... $ 6000 per head. Given that many (like children, beneficiaries and many super annuitants) contribute less than they pay is this in average more than $ 10.000 per net taxpayer. Think about how long you need to work extra to fund your contribution (be it as taxpayer or as electricity user)

Will take an eternity to get the money back if everything goes well (but how likely is this?) and lots of money burnt if the big one in the Southern Alps destroys this next Think Big project.

Looks like we haven't learned from Muldoon ... and I thought he might have been good for something. Apparently not.

Ah well, its just money and maybe some more flooded houses, how bad can it be? Lets do it ...

Ferg

16-03-2023, 07:40 PM

Looks like we haven't learned from Muldoon ... and I thought he might have been good for something. Apparently not.
Can you explain BP? I have heard commentary lately that says we have a lot to thank Muldoon for with the Think Big Projects. I am genuinely curious to hear the other side of this. I presume you are referring to the Think Big projects...?

I don't see borrowing to invest in energy infrastructure and capacity as a bad thing*, where the benefits accrue over many years or decades. Maybe the subsequent inflationary aspect wasn't handled so well.....I don't know enough about it.
https://en.wikipedia.org/wiki/Think_Big

*I should qualify this where the business case stacks up.

BlackPeter

17-03-2023, 09:52 AM

Can you explain BP? I have heard commentary lately that says we have a lot to thank Muldoon for with the Think Big Projects. I am genuinely curious to hear the other side of this. I presume you are referring to the Think Big projects...?

I don't see borrowing to invest in energy infrastructure and capacity as a bad thing*, where the benefits accrue over many years or decades. Maybe the subsequent inflationary aspect wasn't handled so well.....I don't know enough about it.
https://en.wikipedia.org/wiki/Think_Big

*I should qualify this where the business case stacks up.

We well might be in agreement (given your added qualifier). Can't however remember too many think big projects where the business case did stack up. Can you?

The link you provided thankfully provides already the following summary:

New Zealand's economy suffered from the major investments made by the government. Investment incentives and macroeconomic ratios were heavily affected by the billions of dollars borrowed for the Think Big projects. On 27 September 1982, Muldoon introduced 'The Wage Freeze Regulations' that would freeze wages and prices on a national scale until 22 June 1983.[4] The policy had attempted to target inflation, but in turn reduced profitability for exporters unable to adapt prices.

Approval of Think Big, at least during and soon after the time of its implementation, tended to rely on party affiliations (with National Party supporters backing the projects, while Labour Party supporters initially opposed them).[citation needed] Think Big projects became synonymous with further inflation and industrial trouble. Richard Prebble said to the Labour Cabinet during the Māori loan affair: "Better to talk about the $7 billion that was borrowed (by Muldoon for Think Big) than about the $600 million that wasn’t."[5]

Not a lot I would need to add ...

With Lake Onslow ... given the current price tag (which no doubt will keep rising given inflation, increasing standards, increasing costs in any big project and lots of to be expected resistance in the population), not to mention a number of significant risks (remember - the big one is already overdue) can I not see how anybody could justify this project.

dibble

17-03-2023, 11:14 AM

Lake Onslow to cost $15.7bn (or in the words of a poster in the article below: "yeah right $15.7b x 2 more likely") and gov proceeding to next stage of feasibility planning

https://www.interest.co.nz/public-policy/120351/government-puts-massive-price-tag-potential-lake-onslow-pumped-hydro-scheme

Should perhaps move to a general thread but.....I just cant get my head around this onslow thing. Thats a lot of money especially as most of our power is already a water battery.

Apart from likely doubling in price it assumes energy technology will be roughly the same in 2030 as now.

Surely it is cheaper to wind down the Tiwai smelter crowd, eventually using the existing Manapouri battery purely as reserve to buy time for ever improving technology e.g. tidal energy is making great progress overseas, ditto a radical storage experiment in some place (cant re-find the articles on those, darn it).

Also I imagine most will have a solar panel on the roof to charge the car by 2035 thus distributing the generating capability allowing our other mulitple dams to be as much backup as dominant.

Cant se all that costing $15-30bn altho perhaps I underestimate how many road cones and stop-go consultants will be required.

Bobdn

17-03-2023, 12:17 PM

Nor

17-03-2023, 02:20 PM

Better to just keep Huntly maintained. Burning a little bit of coal and gas from time to time is better than spending $15 to $30 billion.

And you can still go crazy on solar and wind knowing that at least Huntly has your back if it's a cloudy, still day.

So true. Even totally eliminating Nz's tiny contribution to climate change will have zero effect.
Better infrastructure projects to spend it on.

BlackPeter

17-03-2023, 04:10 PM

Better to just keep Huntly maintained. Burning a little bit of coal and gas from time to time is better than spending $15 to $30 billion.

And you can still go crazy on solar and wind knowing that at least Huntly has your back if it's a cloudy, still day.

Don't they have gas turbines as well in Huntley? In 10 years they probably can fuel them with green hydrogen. No need for outrageously expensive storage lakes which may or may not leak (or break :scared: ) during the next earthquake.

fish

17-03-2023, 05:02 PM

Don't they have gas turbines as well in Huntley? In 10 years they probably can fuel them with green hydrogen. No need for outrageously expensive storage lakes which may or may not leak (or break :scared: ) during the next earthquake.
Yes genesis could use clean natural gas instead of dirty coal .
We do need a more pragmatic government that will reverse the hypocritical exploration ban

BlackPeter

17-03-2023, 05:10 PM

Yes genesis could use clean natural gas instead of dirty coal .
We do need a more pragmatic government that will reverse the hypocritical exploration ban

Agreed - the exploration ban was clearly quite counterproductive, wasn't it? But I talked about green hydrogen ... in 10 years we have hopefully facilities producing this stuff in NZ from spare hydropower ... and this could be used in (modified) gas turbines to produce power when we need it. No need for a hugely expensive storage lake cantered between several fault lines ...

Ferg

17-03-2023, 05:16 PM

We well might be in agreement (given your added qualifier). Can't however remember too many think big projects where the business case did stack up. Can you?
Thanks for the reply.

I was originally looking at this as two different issues: the first being the provision of energy self sufficiency and/or capacity (with the late disclaimer I added) and the the second issue being the rampant inflation that followed with the drastic & draconian policies to curb it. I never looked into it that closely to see if the inflation was caused by 'Think Big' borrowing and expenditure or by the oil price shocks of the time, or a combination of the two. Or possibly even something else? It would be interesting to see some post-analytical work on that. Although I note that one such project, the Clyde Dam, was built between 1982 and 1993 during which time we did not have rampant Muldoon inflation.

I'm not sure that link I provided adequately proves the connection between think big expenditure and subsequent inflation. So whilst I suppose we can be thankful to RM for the additional capacity, some of that could be withdrawn for the downstream economic impacts perhaps. I wonder how long it will be before we regret decommissioning Marsden Point Refinery, if not already? I haven't seen the economics for the Clyde Dam but I'm guessing we as a country are now thankful to have that additional electricity generation capacity.

Although would the economic impacts have been worse without these projects? On that note, I have never seen any of the business cases for the projects. I wonder if they are they still available and what they were projecting would happen if the projects did not proceed. That said, we are on an island at the bottom of the world - so I would probably also support *some* energy projects that increased future resilience and capacity that were marginal business cases.

Edit: in conclusion, I would not want to see us fall into the same mistakes made by previous Governments. And to your last post , I agree we should be looking at hydrogen as a fuel source. That makes sense to me.

kiora

17-03-2023, 07:42 PM

Better to just keep Huntly maintained. Burning a little bit of coal and gas from time to time is better than spending $15 to $30 billion.

And you can still go crazy on solar and wind knowing that at least Huntly has your back if it's a cloudy, still day.

Or makes more sense to invest in biomass conversion???
"Genesis isn’t considering further imports of wood. Instead, it wanted to develop a local source of pellets or “biomass”, said interim chief executive Tracey Hickman.

“It’s worth some focus by government and business to see if a sustainable local supply chain can be developed. Compared to some other decarbonisation solutions, biomass conversion could be implemented much sooner to the benefit of the country,” she said in a statement.

With a reliable supply of pellets, Hickman said, Huntly could become a lower-carbon source of back-up electricity generation for another decade – or even longer."
https://www.stuff.co.nz/environment/climate-news/131298611/huntly-burns-wood-instead-of-coal-during-short-trial

Or biogas ???
https://www.beca.com/getmedia/4294a6b9-3ed3-48ce-8997-a16729aff608/Biogas-and-Biomethane-in-NZ-Unlocking-New-Zealand-s-Renewable-Natural-Gas-Potential.pdf

fish

17-03-2023, 08:21 PM

Or makes more sense to invest in biomass conversion???
"Genesis isn’t considering further imports of wood. Instead, it wanted to develop a local source of pellets or “biomass”, said interim chief executive Tracey Hickman.

“It’s worth some focus by government and business to see if a sustainable local supply chain can be developed. Compared to some other decarbonisation solutions, biomass conversion could be implemented much sooner to the benefit of the country,” she said in a statement.

With a reliable supply of pellets, Hickman said, Huntly could become a lower-carbon source of back-up electricity generation for another decade – or even longer."
https://www.stuff.co.nz/environment/climate-news/131298611/huntly-burns-wood-instead-of-coal-during-short-trial

Or biogas ???
https://www.beca.com/getmedia/4294a6b9-3ed3-48ce-8997-a16729aff608/Biogas-and-Biomethane-in-NZ-Unlocking-New-Zealand-s-Renewable-Natural-Gas-Potential.pdf

No shortage of biomass.
Would it not make sense to use the waste logs that can cause flood damage .
I also wonder if the ashes/waste resulting would be a good phosphate/potassium /trace elements fertiliser

fish

17-03-2023, 08:28 PM

Agreed - the exploration ban was clearly quite counterproductive, wasn't it? But I talked about green hydrogen ... in 10 years we have hopefully facilities producing this stuff in NZ from spare hydropower ... and this could be used in (modified) gas turbines to produce power when we need it. No need for a hugely expensive storage lake cantered between several fault lines ...

I do feel hydrogen in the scale needed would be difficult to store and require expensive technology to produce large amounts electricity.
We have natural gas stored in abundance if the government would lift the ban-costing the taxpayer nothing .
Look how well Norway is doing with their hydro and gas

BlackPeter

18-03-2023, 09:39 AM

I do feel hydrogen in the scale needed would be difficult to store and require expensive technology to produce large amounts electricity.

...

It appears that scientists in Europe do see that differently ... they have big plans for green hydrogen for 2030. Gosh, that's only 7 years away!

https://energy.ec.europa.eu/topics/energy-systems-integration/hydrogen_en#:~:text=The%20ambition%20is%20to%20pro duce,in%20energy%2Dintensive%20industrial%20proces ses.

Anyway - I agree that gas is still much better than burning dirty coal ... and Europe uses this currently as well as place-filler.

And of course - NZ is often at least 30 years behind the rest of the world related to anything environmentally positive. Last developed country to phase out leaded petrol and one of the last civilised countries to allow the uncontrolled application of RoundUp and one of the largest per head producers of rubbish - i.e. for the specific NZ conditions you well might be right ... we well might need longer than anybody else to produce and store green hydrogen :p ;

Green NZ - LOL.

fish

18-03-2023, 10:48 AM

Thanks for the link bp
Those projects to fuel Europes ambitions are likely to be out of the league for government finances and without looking deeper into them I am sceptical as to how successful or green they will be.
At this time most hydrogen is produced from natural gas so big co2 emissions .
Greens and Labour should ban dirty coal imports now and support natural gas production instead of chasing gas producers away .
Their green policy is in reality dirty black

BlackPeter

18-03-2023, 11:11 AM

Greens and Labour should ban dirty coal imports now and support natural gas production instead of chasing gas producers away .
Their green policy is in reality dirty black

We agree on that. Suppose however that our industry missed through the ban 5 years ago a crucial time window ... too long to catch up before the gas window is going to close.

I think we should go the green hydrogen way. We do have cheap renewable energy (to produce the hydrogen) and we have plenty of space to store it safely away from large population centres. The capital will come, if we invite it. Look at Canadas recent MoU with the EU:

https://www.cbc.ca/news/canada/newfoundland-labrador/canada-germany-hydrogen-partnership-nl-1.6559787#:~:text=Instead%2C%20Prime%20Minister%20 Justin%20Trudeau,called%20it%20a%20historic%20mome nt.

Why can't we do something similar as well - e.g. with Singapore?

dibble

18-03-2023, 03:25 PM

I do feel hydrogen in the scale needed would be difficult to store and require expensive technology to produce large amounts electricity.
We have natural gas stored in abundance if the government would lift the ban-costing the taxpayer nothing .
Look how well Norway is doing with their hydro and gas

....and then in a decade or so when wind/gas/solar etc has expanded and Manapouri returned to the national grid, below is thrown into the mix:
https://spectrum.ieee.org/electric-vehicle-grid-storage

"Electric-vehicle batteries may help store renewable energy to help make it a practical reality for power grids, potentially meeting grid demands for energy storage by as early as 2030, a new study finds."

Still difficult to see Onslow as a sensible pursuit.

fish

19-03-2023, 11:56 AM

....and then in a decade or so when wind/gas/solar etc has expanded and Manapouri returned to the national grid, below is thrown into the mix:
https://spectrum.ieee.org/electric-vehicle-grid-storage

"Electric-vehicle batteries may help store renewable energy to help make it a practical reality for power grids, potentially meeting grid demands for energy storage by as early as 2030, a new study finds."

Still difficult to see Onslow as a sensible pursuit.

Smaller scale pumped hydro in the north island seems much more sensible-I understand this is being considered as an option .
I do wonder if it could be financed part government and part private-maybe with genesis ?

kiora

11-04-2023, 08:38 AM

Or makes more sense to invest in biomass conversion???
"Genesis isn’t considering further imports of wood. Instead, it wanted to develop a local source of pellets or “biomass”, said interim chief executive Tracey Hickman.

“It’s worth some focus by government and business to see if a sustainable local supply chain can be developed. Compared to some other decarbonisation solutions, biomass conversion could be implemented much sooner to the benefit of the country,” she said in a statement.

With a reliable supply of pellets, Hickman said, Huntly could become a lower-carbon source of back-up electricity generation for another decade – or even longer."
https://www.stuff.co.nz/environment/climate-news/131298611/huntly-burns-wood-instead-of-coal-during-short-trial

Or biogas ???
https://www.beca.com/getmedia/4294a6b9-3ed3-48ce-8997-a16729aff608/Biogas-and-Biomethane-in-NZ-Unlocking-New-Zealand-s-Renewable-Natural-Gas-Potential.pdf

Here you go at last, large opportunity ?
https://www.stuff.co.nz/business/131708888/biogas-from-kerbside-waste-collections-to-be-mixed-into-natural-gas-network-next-year?utm_source=ST&utm_medium=email&utm_campaign=ShareTrader+AM+Update+for+Tuesday+11+ April+2023

Onemootpoint

11-04-2023, 10:06 AM

Here you go at last, large opportunity ?
https://www.stuff.co.nz/business/131708888/biogas-from-kerbside-waste-collections-to-be-mixed-into-natural-gas-network-next-year?utm_source=ST&utm_medium=email&utm_campaign=ShareTrader+AM+Update+for+Tuesday+11+ April+2023

Interesting; a hint that others may follow too.

mwri

11-04-2023, 10:38 AM

The big oil giants have been investing big in renewable natgas and the space has really been picking up steam.

kiora

11-04-2023, 11:53 AM

And then there is this syngas, coal seam gas
https://www.ergoexergy.com/about_us_ourb_projects_solid.html
Of which nothing more has been heard
https://ir.canterbury.ac.nz/handle/10092/1304

RTM

11-04-2023, 02:26 PM

http://nzx-prod-s7fsd7f98s.s3-website-ap-southeast-2.amazonaws.com/attachments/CEN/408963/391433.pdf

The attached presentation by contact had a good summary of various aspects of the NZ Energy Market.
Quite interesting....even if one wasn't interested in the bonds.

dibble

15-04-2023, 03:49 PM

BlackPeter

15-04-2023, 04:28 PM

Yet another alternative.

Canberra megabattery to hold 250MW. Onslow expected to hold....1000-1200MW?? depending on which news source you read (Newsroom v Stuff).

https://www.abc.net.au/news/2023-04-13/big-canberra-battery-finds-owner-in-eku-energy/102217104

"Expected to be online in 2025, the battery energy storage system will cost between $300 million and $400 million".
Looks like construction hasnt started yet.

....so one can be built in about 2 years? Maybe 4-5 of them would roughly match Onslow?? No birds or lizards displaced and maybe total under $2bn in a 2-4 year timeframe plus you could put them in the North Is where needed.
Just charge them during summer with a solar field.

There must be a catch of course, be interested to hear what that is from those in the know. I didnt see Contact's presentation refer to any alternatives.....
(thanks RTM by the way)

I am sure there are better alternatives than lake Onslow. However - while your calculation looks at face value sensible, I think that you did fall victim of reports written by reporters not understanding the difference between storage capacity (measured in kWh, MWh, GWh or TWh) and generating power (measured in kW - or MW).

Just to clarify the units: 1TWh (i.e. 1 Tera Watt hour) = 1000 GWh, 1 GWh = 1000 MWh, 1 MWh = 1000 kWh; 1 MW = 1000 kW;

100 MW might be the generating capacity of the turbines - i.e. they could produce 100 MWh - every hour.

The storage capacity is a different thing. This is how long you could supply the 100 MW capacity before the lake is empty. For Lake Onslow this would be something like 5 Tera watt hours - i.e. 50,000 hrs of 100 MW generation. This is a lot of energy if you want to put it into batteries.

mfd

15-04-2023, 04:29 PM

Yet another alternative.

Canberra megabattery to hold 250MW. Onslow expected to hold....1000-1200MW?? depending on which news source you read (Newsroom v Stuff).

https://www.abc.net.au/news/2023-04-13/big-canberra-battery-finds-owner-in-eku-energy/102217104

"Expected to be online in 2025, the battery energy storage system will cost between $300 million and $400 million".
Looks like construction hasnt started yet.

....so one can be built in about 2 years? Maybe 4-5 of them would roughly match Onslow?? No birds or lizards displaced and maybe total under $2bn in a 2-4 year timeframe plus you could put them in the North Is where needed.
Just charge them during summer with a solar field.

There must be a catch of course, be interested to hear what that is from those in the know. I didnt see Contact's presentation refer to any alternatives.....
(thanks RTM by the way)

You're getting your units mixed up here - MW is the power that the schemes can release. That is, when charged/filled, this battery can release 250 MW of power to the grid, while Onslow could release ~1000 MW. The energy stored is quite different.

From that article, if the battery is fully charged it can release power for 2 hours before exhausting itself. This suggests a storage capacity of about 500 MWh. Onslow is intended to hold a capacity of 5 TWh, or 5,000,000 MWh. You'd need to build 10,000 megabatteries to replicate that, at a cost of something like $3 trillion AUD. Onslow can storage this energy for a period of years, losing a small amount due to evaporation. How well do these batteries hold charge?

Grid scale batteries are useful, but they are answering a completely different question to Onslow. Battery tech would need to improve by several orders of magnitude to compete with pumped hydro on the 'dry year' issue.

dibble

16-04-2023, 09:40 AM

MFD/BP, thanks both for taking the time to clarify.

Had a nasty feeling after posting I hadnt quite nailed the maths.... ("quite" obviously being an understatement)

Sideshow Bob

14-08-2023, 08:35 AM

https://www.nzx.com/announcements/416270

Contact delivers solid FY23 performance while investing for decarbonisation

Key financial metrics

[please see table in attached announcement]
Overview

New Zealand renewable energy company Contact Energy (‘Contact’) today released its financial results for the year to 30 June 2023.

- Net profit of $127m after recognising an onerous contract
provision expense of $84m ($113m EBITDAF impact) following a
review of the estimated available capacity of the Ahuroa Gas
Storage facility (AGS). Excluding AGS, underlying net profit
was $211m.

- Underling EBITDAF (excluding the AGS provision) increased by
$27m to $573m with higher realised electricity pricing and a
gain on sale of the Te Rapa co-generation plant, partially
offset by high gas and carbon unit costs, lower electricity
sales volumes and higher fixed operating costs.

- Operating free cash flow decreased by $48m to $282m. Working
capital continues to be elevated, with more gas and carbon
units in inventory.

Contact has made significant progress on delivering to its Contact26 strategy and remains focused on leading New Zealand’s decarbonisation by connecting customers with its renewable development pipeline.

- New geothermal station of up to 180MW at Te Mihi, GeoFuture,
proceeding to final investment decision in early 2024.
Investment of up to $114m approved. Pre-construction drilling
to begin from September 2023.

- Preparing for final investment decisions on Kōwhai Park 170MWp
solar farm and 100MW North Island battery in FY24.

- Planning to apply for resource consent at Glorit on the Kaipara
Coast, northwest of Auckland by the end of 2023 for the second
160MWp solar farm through Contact’s joint venture with
Lightsource bp.

- Te Rapa power station closed on 30 June 2023 as planned.
Contact’s generation on track to be more than 95% renewable by
FY27.

- Strong endorsement of Contact’s retail offering, reaching
approximately 589,000 energy and broadband connections.

- Introduced wireless broadband and Dream Charge time-of-
use plan, enabling customers to charge their EVs at home
at lower night rates, contributing to the decarbonisation
of New Zealand. Contact Mobile launches later this month.

- Supported mass market customers by keeping average
electricity price increase realised year-on-year in line
with general inflation, despite elevated forward
wholesale prices over the last three years.

Financial performance

In FY23 Contact recognised an onerous contract provision expense of $84m after tax ($113m EBITDAF impact) following a review of the estimated available storage capacity of AGS. This is a non-cash accounting adjustment to recognise the difference between the expected benefits from access to gas storage and the contracted schedule of payments over the remaining 10 years of the contract.

Reported net profit of $127m was down $55m on the prior year, with lower operating earnings (EBITDAF) reflecting the onerous contract provision, higher interest expense reflecting the higher interest rate environment and unfavourable movements in the fair value of financial instruments as higher losses were realised from unhedged financial instruments, partially offset by lower depreciation and amortisation and lower tax on earnings. Excluding the impact of the AGS provision, underlying net profit was $211m, up $29m from the prior year.

Underlying EBITDAF, which excludes the impact of the AGS provision, increased by $27m to $573m, up five percent on the prior year, with higher realised electricity pricing as our sales channels align closer to the wholesale market, and higher other income which included a $7m gain on sale of Te Rapa. This was partially offset by continued higher thermal generation input costs, lower electricity sales volumes and higher fixed costs driven by inflation and the preparation of the business for growth.
Operating free cash flow decreased from $330m to $282m, down 15 percent year-on-year with higher underlying operating earnings offset by higher stay-in-business capital expenditure, higher cash tax paid on strong earnings in prior periods and unfavourable working capital movements. Working capital remained elevated as Contact held more gas and carbon units in inventory on lower thermal generation than the prior year.

The Board approved a final dividend of 21 cents per share (imputed by up to 18 cents per share for qualifying shareholders) to be paid on 26 September 2023; taking the annual dividend declared for FY23 to 35 cents per share, which is in line with the prior year.

“Contact delivered a solid financial performance despite soft short-term wholesale market conditions,” said Mr Fuge.

“We saw the highest nationwide hydro inflows in post-market history, with North Island rainfall the highest on record. This depressed spot market prices and saw greater price separation between the North and South Islands. We responded by purchasing excess renewable electricity from the wholesale spot market and reduced our thermal generation to the lowest in Contact history.”

Renewable development

Contact’s geothermal development activity is moving at pace, with plans to replace the 1950s-built Wairākei A and B power stations with a new station of up to 180MW at Te Mihi – the GeoFuture project. Development costs of up to $114m have been approved and Contact is targeting a final investment decision in early 2024.
“It is an exciting time for Contact as we focus on advancing our steamfield design work for GeoFuture and we will start pre-construction drilling in September. This comes as we are reaching completion of our world-class geothermal development at Tauhara,” said Mr Fuge.

The Minister for the Environment has approved the Southland Wind Farm Project for fast-track consenting. If approved, the 300MW facility would be Contact’s first wind farm and New Zealand’s largest. Together with its partner, Roaring40s, Contact continues to engage with local communities and mana whenua.

Subject to taking a final investment decision in FY24, Contact’s joint venture with Lightsource bp will begin construction on a 170MWp solar farm at Christchurch Airport, Kōwhai Park in 2024. The joint venture’s second proposed solar farm development is in Glorit on the Kaipara Coast, northwest of Auckland. The proposed site has good access to the transmission grid and is expected to generate 0.3TWh per year. The joint venture plans to apply for consent for the Glorit site in the second half of 2023.

Demand
Industry interest in converting to renewable electricity was strong, Mr Fuge said.

“In May we announced a pioneering energy agreement with NZ Steel. We will provide 30MW of flexible off-peak renewable electricity for its proposed new $300m electric arc furnace. This will enable NZ Steel to scale down production in peak demand times or supply shortages, with the project representing a significant step towards meeting New Zealand’s climate change goals.”

The trend continued with accelerating opportunities with several other industrial companies exploring similar opportunities to decarbonise industrial heat processes and cut fossil fuel use.

The New Zealand Aluminium Smelter (NZAS) has indicated it would like to continue operations at Tiwai Point beyond December 2024. “We are encouraged as we continue to work closely with NZAS to negotiate a new agreement. The smelter is valuable to our country, and our economy, particularly as a significant exporter. It is also highly carbon efficient in its production of premium aluminium, and a major employer and contributor to the Southland economy.”

Decarbonising our portfolio

In June 2023, as planned, Contact closed its 44 MW Te Rapa gas-fired co-generation power station. And the company has confirmed it won’t extend the operating hours of its gas-fired Taranaki Combined Cycle (TCC) plant. While it will support security of supply with remaining operating hours, decommissioning is expected at the end of 2024.

The 1.9TWh of new renewable generation that Contact will be bringing online at Tauhara and Te Huka is enabling Contact to take these steps. And, after a successful trial at Te Huka, Contact has confirmed it is exploring the feasibility of CO2 capture and reinjection or reuse across existing and planned geothermal plants.

“This year we have taken key steps towards decarbonising our own portfolio and now have a clear path to achieve net zero emissions from our generation operations by 2035. We are committed to doing this in an orderly manner, ensuring security of supply and energy affordability to New Zealanders,” said Mr Fuge.

In line with Contact’s decarbonisation strategy, the company will be taking a final investment decision on a 100MW battery in FY24. Contact has a preferred site option at Glenbrook, subject to consenting, and has resource consent to build at Stratford where Contact has existing operations.

“Investment in renewable energy flexibility in the North Island, close to retail load, is key to our strategy to lead New Zealand’s decarbonisation. With more intermittent renewables being introduced, grid-scale batteries will play an important role by storing energy during periods of low demand and discharging power into the grid during the peaks. This investment will reduce our reliance on gas peaking plant and will enable us to participate across physical, reserve and frequency-keeping markets,” said Mr Fuge.

Retail

Mr Fuge said Contact’s retail business has continued with targeted growth in FY23. “Multi-product customers are up 10% on FY22 driven by growth in our broadband business and supported by the introduction of fixed wireless broadband and expanded time-of-use offerings with the new Dream Charge EV plan. We’ve also been preparing to introduce Contact mobile, which will launch later this month.” Contact has been named as a finalist for Energy Retailer of the Year for the second year running.

Outlook

Looking ahead, Mr Fuge said the coming year will see Contact reaching significant milestones in the delivery of its strategy to lead the decarbonisation of New Zealand.
“We’re preparing for Tauhara to come online by the end of the year, which will be a pivotal moment for the company. We’re well on track to bring Te Huka 3 online by the end of 2024 and we’ll be taking final investment decisions on GeoFuture, Kōwhai Park and a 100MW battery all within this financial year. I’m exceptionally proud of the team’s dedication in laying the groundwork to realise our strategy.”
“We are excited about the future. We have a clear strategy, strong balance sheet with supportive shareholders and stand ready to execute on the opportunities in front of us to lead the decarbonisation of the New Zealand economy over the next decade.”

1/ MORE INFORMATION
Investors:
Shelley Hollingsworth
Investor Relations & Strategy Manager shelley.hollingsworth@contactenergy.co.nz
+64 27 227 2429
Media:

winner69

14-08-2023, 08:51 AM

Report reads amazingly good but there are some big down numbers but as long as we focus on normalisation and the good things suppose all is fine.

In some respects I’m glad I don’t try to hard to understand how these companies work…..seems very messy and complicated

No pay rise for share holders this year

RTM

14-08-2023, 09:15 AM

winner69

14-08-2023, 09:20 AM

And taking inflation into account Winner ?

So really it’s a pay cut

Govt should consider cutting GST on power bills so retirees depending on their CEN divie as income don’t suffer too much

RTM

14-08-2023, 11:25 AM

So really it’s a pay cut

Govt should consider cutting GST on power bills so retirees depending on their CEN divie as income don’t suffer too much

Yes. Good idea. Another non-targeted bit of tax relief. I suspect most people depending on the contact dividend are doing pretty well overall.

troyvdh

14-08-2023, 01:15 PM

winner69 I love your sense of humour.

Sideshow Bob

19-02-2024, 09:03 AM

https://www.nzx.com/announcements/426369

Contact Energy performance demonstrates underlying business health; Focus on asset delivery

Financial performance

Contact Energy has reported net profit of $153m in 1H24 and operating earnings (EBITDAF) of $354m. Reported figures include a net provision release relating to the Ahuroa Gas Storage facility (AGS) onerous contract of $29m within EBITDAF ($19m within net profit after tax and interest). Excluding the provision release, underlying net profit was up 70% on 1H23 to $134m and EBITDAF was up 26% to $325m.

The improved operating result was driven by closer alignment of channel pricing to the wholesale market and greater thermal efficiency, partially offset by lower hydro generation, reduced steam revenue following the closure of Te Rapa and one-off write-offs of $8m relating to damage to Peaker assets and the CRM system upgrade programme not continuing as originally planned.

Hydro volatility characterised operating conditions throughout the period, with flow-on impacts to wholesale pricing from more thermal generation. Contact increased contracted sales volumes in anticipation of Tauhara coming online in 4Q 2023 and with the delay to 3Q 2024 applied some mitigations to meet this position. At the same time, Contact has executed well on its channel mix and pricing strategies.

“The result has been a demonstration of strength in our underlying performance, setting us up well for the year ahead and we now expect to deliver underlying EBITDAF of $620m in FY24,” says Chief Executive Mike Fuge.

Operating free cash flow of $187m was up 163% on the prior year on the improved operating result, relatively lower levels of working capital due to higher thermal generation and lower tax paid on FY23 profit, partially offset by accelerated stay in business capex. The Board declared an interim dividend of 14 cents per share, in line with 1H23.

Demand

Negotiations with Rio Tinto have been constructive and have re-enforced Contact’s long-held view that the New Zealand Aluminium Smelter (NZAS) appears likely to stay. Contact is expecting a new agreement to be long-term, at a fair price materially above the current pricing, and including demand response (mitigating dry-year risk).

“A new long-term agreement would de-risk investment in new renewable generation, contribute to energy security and help to preserve an important export industry, supporting growth and decarbonisation of the New Zealand economy,” said Mr Fuge.
Renewable development

Remediation works got underway at Contact’s Tauhara geothermal development in November and re-construction of the steam separation plant is near complete. Tauhara is expected to come online in Q3 2024 at the initial design capacity of around 152MW (expecting 174MW from the first planned outage in 2025), and Te Huka 3 is on track to follow in Q4 2024.

“I’m extremely proud of the team that has worked hard over the summer to get Tauhara back into the full swing of commissioning. Both Tauhara and Te Huka will join Contact’s renewable generation fleet in 2024 and will add 1.9TWh per annum of baseload renewable output once full capacity is reached.”

Drilling, advanced steamfield design and tendering have progressed to prepare for a final investment decision in 2024 on GeoFuture, the replacement of Contact’s 65-year-old Wairākei geothermal plant. Final investment decisions are also expected in 2024 on a 100MW North Island battery and the Kōwhai Park solar development.

“These investments in new renewable technologies will contribute to security of supply as New Zealand decarbonises, said Mr Fuge”.

Decarbonising the portfolio

Emissions intensity from thermal generation was down ~30% on 1H23 driven largely by the closure of Te Rapa on 30 June 2023. Portfolio decarbonisation is just one aspect of Contact’s broader commitment to sustainability, which in December saw Contact win both the Sustainability Leadership award in the Deloitte Top 200 and move into the number one ranking of participating New Zealand companies in the DJSI Asia Pacific.

Contact expects to decommission its combined cycle gas generation plant (TCC) at the end of 2024. A planned outage at TCC was brought forward and completed in December with additional operating hours approved. Contact has also worked to accelerate the return of its spare peaker engine and is expecting GT22 to be in service for winter 2024.

Retail

Retail electricity net price has improved in light of rising energy and pass-through costs. Total connections were up 20,000 on 1H23, driven primarily by broadband. Contact also expanded its telecommunication offering with the introduction of Contact Mobile and boosted its time of use offerings with the introduction of Good Weekends. Contact remains focused on supporting our customers in energy hardship through ERANZ, with offerings like ConnectMe and EnergyMate, and directly with community groups like Women’s Refuge and Good Shepherd. Over the last twelve months Contact has provided in excess of one million dollars to directly support customers in energy hardship.

Outlook

Looking ahead, Mr Fuge said the next six months will see Contact reaching significant milestones in the delivery of its strategy to lead the decarbonisation of New Zealand.

“We are excited about the future. We have a clear strategy, strong balance sheet with supportive shareholders and stand ready to deliver on the opportunities in front of us to lead the decarbonisation of the New Zealand economy over the next decade.”