Victoria’s new renewables policy, and why it could learn from South Africa | RenewEconomy

Victoria’s new renewables policy, and why it could learn from South Africa

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Victoria plans biggest investment in new generation capacity in Australia since creation of the National Electricity Market. It would do well to learn from South Africa.

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The Victorian government recently announced a policy to decisively increase the amount of renewable generation in Victoria. The rationale for this policy is that existing federal policies are failing to provide investment certainty in the expansion of renewable production capacity.

The government estimates that meeting its policy will require up to 5,400 MW of new renewable generation to be built over the next nine years. This is equivalent to about 60 per cent of Victoria’s peak demand on the power grid.


Assuming an all-in capital outlay per MW of $2.5 million, meeting this policy could require $13.5 billion of new money. Some significant investment in transmission infrastructure is also likely to be needed. After residential rooftop solar, this will be, by far, the largest investment in new generation capacity in Australia since the creation of the National Electricity Market.

Last month a consultation paper from the Department of Environment, Land, Water and Planning sought responses on various issues (identity of the counter-party, specification of the payment instrument, technology selection, treatment of other subsidies, contract duration and auction design). The Department is currently focusing on the preparation of enabling legislation with a view to conducting its first tender next year.

South Africa’s Renewable Energy IPP Procurement Program (REIPPPP) is an interesting point of reference, of comparable scale, to the Victorian policy. Though there are many differences, many of the important issues are similar and much can be learned from the South African experience. At the least, a quick look at their program we might give a sense of what lies in store for Victoria.

Under the REIPPPP program 6,327MW (of which 3,357 MW of wind in 34 projects, 2,292 of PV in 45 projects, 600 MW of concentrated solar in 7 projects and several much smaller biomass and small hydro projects) have been awarded PPAs. Total capital outlays of around $19bn are expected, to complete these projects. As a result of this, since 2012, South Africa has ranked among the top ten countries globally in terms of renewable energy independent power producer investment.

In the first tender in November 2011, 28 projects offering 1,416 MW in total were selected. In the second round in May 2013, 19 projects offering 1,040 MW were selected. A third round in August 2013 selected 15 projects for 1,321 MW. A fourth round in August 2014 selected 26 projects for 2,207 MW. A fifth round is expected to commence shortly.

The bidders offer prices for 20 year Power Purchase Agreements with Eskom, the government owned national power monopoly. Two additional agreements with the Government underwrite Eskom default risks, provided step-in rights to lenders in the case of default and ensure contractual obligations for delivery of up to 17 economic and social development obligations. Community ownership (at not less than 2.5% of the total project cost) is mandatory and the developer have to come up with ways, such as community trusts, to comply with this. Contract evaluation is based 70% on price and 30% on socio-economic factors.

The contracts are not negotiable and bidders are required to submit bank letters to the effect that financing is locked-in. This effectively outsources due diligence to the lenders. The lenders in turned passed this on to developers but in a way that ensured the duty of care was to lenders.

The 64 successful projects in the first three rounds involved over a 100 different shareholder entities, 46 of these in more than one project. Banks, insurers, development banks, international utilities and direct foreign investors have all participated in the program. The most common financing structure has been project finance, although about a third of the projects in the third round used corporate finance.

The majority of debt funding has been from commercial banks with the balance from development banks, pension and insurance funds. Eighty-six percent of debt has been raised from within South Africa on 15-17 year loans (from Commercial Date of Operation). Debt risk premia in bank loans have been around 450 basis points on top of the South African equivalent to Australia’s 90 day bank bill swap rate.

Forty-nine Engineering, Procurement and Construction (EPC) contractors have been involved in the 64 projects during the first three rounds, the majority in more than one project either as the primary or secondary contractor.

Prominent EPC contractors with three or more projects include Vestas (Danish), Acciona (Spanish), Consolidated Power Projects (South African), Group Five Construction (South African), Juwi Renewable Energies (German), Murray and Roberts (South African), Abengoa (Spanish), ACS Cobra (Spanish), Iberdrola Engineering and Construction (Spanish), Nordex Energy (Germany), Scatec (Norwegian), Suzlon (India), and Temi Energia (Italian). Many of these EPC contractors have set up subsidiary companies in South Africa.

The main suppliers of wind turbines and PV equipment include Vestas, Siemens, Nordex, ABB, Guodian, Suzlon, Siemens, SMA Solar Tech, BYD Shanghai, Hanwha Solar, 3 Sun, AEG and ABB. A local wind tower manufacturing facility and at least five PV panel assembly plants have been established in South Africa.

Over the period of the four bidding rounds, offered prices per MWh halved for wind and concentrated solar and declined by 75% for solar PV. Global technology development, local economies of scale, improving investor confidence and lower transaction costs explain this stunning progress.

As the volume of renewable capacity has increased, transmission connection has been become an increasing concern. Bidders are responsible for connection to the nearest major substation, but augmentation of the shared network is lagging behind and this has become a particular issue for the most recently awarded projects.

The World Bank suggests the most important lesson to transfer from the REIPPPP is the benefits of a well-designed and transparent procurement process. They say that the Department of Energy recognised that it had little capacity to run a sophisticated multibillion-dollar competitive bidding process for renewable energy.

As a consequence, it sought the assistance of the National Treasury’s Public-Private Partnership (PPP) Unit to manage the process. A small team of technical staff from DOE and the PPP Unit established a project office which functioned effectively outside of the formal departmental structure of national government. It was led by a senior manager from the National Treasury PPP Unit and other legal and technical experts were brought on board to form a tightknit team.

This was viewed favorably by both the public and private sector as a professional unit with considerable expertise in closing PPP contracts and a reputation as problem solvers and facilitators rather than regulators. The credibility of this team with the bankers, lawyers, and consultants involved in such projects in South Africa generated enthusiastic participation by private sector players.

The World Bank reports that high standards were set and maintained throughout the bidding process, including security arrangements and transparent procurement procedures. Documentation was extensive, high quality, and readily available. Domestic and international advisers were extensively involved in the design and management of the program, in reviewing bids, and in incorporating lessons learned into the program as it progressed through the bid rounds.

To fund the procurement process, in 2011 the National Treasury provided R100 million (around $10m). The World Bank provided a further US$6m and various bi-lateral donor agencies from Denmark, Germany, Spain and the UK contributed funding for technical assistance. This funding saw the program through the first round and part of the second. Subsequent to that, the program relied on bidder registration fees and fees paid by successful IPP project companies.

Successful project companies must pay a project development fee of one percent of total project costs to a Project Development Fund for Renewable Energy projects managed by the Department of Energy. The fund covers current and future costs associated with procurement of renewable energy and oversight of the program. These funding arrangements have helped the program remain off the formal government budget in subsequent bidding rounds.

Coming back home again, the Victorian Government’s policy marks a major departure in the state’s energy policy. Since privatising the industry a little under twenty years ago, the Government has had a watching brief with some intervention around the edges – most significantly in smart meters. The Government is now getting back into the business of electricity production.

Even if it does not intend to own or operate generators, it is the Victorian Government that will under-write what will be a massive investment program. Surely every large new renewable generator developed in Victoria for the next nine years will be part of its program. If the Government legislates its policy as expected, the Victorian Government will become the most important player in the Victoria’s electricity generation sector.

We all, including the Government, have yet to discover how its policy will unfold in practice.

The South African experience can provide some feeling for what goes into the competitive procurement and development of 6,000 MW of renewable capacity. Their apparent success in this endeavor is encouraging. It would be good to learn from this what we can.

Bruce Mountain is an energy economist and Director of consultancy, CME. Vivienne Roberts is an engineer and accountant and was a technical advisor on a number of projects in South Africa.

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  1. David leitch 4 years ago

    Great note. Of course the ACT has worked through a number of these issues also albeit on a smaller scale. Transmission is always an issue. Victoria is the least suitable mainland market for solar so would be better if the Victorian commitment could be partly sourced from energy supplied out of State. The natural order of things would see solar in the North/West of East Australia and wind in the South East connected by transmission and augmented by distributed generation.

    • Peter F 4 years ago

      While there would be slight efficiency gains in north western NSW compared to say northern Victorian locations near Mildura or North West of Bendigo, It is difficult to believe that those gains would offset the capital costs and transmission losses. Leaving aside the question of storage if Victoria was to obtain 40% of its power from solar of which 70% is from large scale farms the area of the farms at 20% site density is only about 400 sq km. or a rectangle 20km on a side. Because it is only 20% land utilisation the land can still be used for grazing. Thus there is absolutely no problem finding sufficient land,

      Because solar panels are now so cheap If the solar farms were as far as possible put on large warehouses, schools etc close to loads, the saving in T&D losses and capital charges would more than offset the cost of about 25% more panels that would be required. The NREL in the US has estimated that about 14% of US roofs would supply about 30% of US power demand and completely meet peak load. Because of lower industrial demand, larger average building space per person and better average insolation the figure should be even better for Victoria.

      There is a stronger case for dispersing wind farms interstate and possibly building a second basslink so that the wind supply is more diversified and Tassie hydro/wind can work in tandem with Victorain/SA wind and solar.

  2. Analitik 4 years ago

    This whole article is about capital cost for deployment. What about the gas supply that will be needed to fill in supply when there is insufficient wind/sun?

    Victoria’s demand is about 3 times that of South Australia so if gas pricing is causing spikes with current usage, what will happen if Victoria went to a similar level of commitment to renewables?

    And since the South Australian and Victorian weather is often correlated, where will the power for the Heywood interconnector come from when both states are experiencing insufficient wind/sun to generate vs demand?

    • Tom 4 years ago

      Gas won’t change. More wind in VIC will mean coal in VIC and NSW will turn down but not off. Note that NSW coal is the marginal unit around the NEM most commonly.

      • Analitik 4 years ago

        Victoria will turn to more gas for its rapid response if more wind and solar are deployed. Coal will not have the capability to ramp up (or down) for when the wind suddenly drops out or cuts in as it does all too often if you check the Aneroid site (try below and limiting to SA & Vic)

        • Tom 4 years ago

          VIC gas is peaker only not CCGT so it won’t be running and available to fill in any gaps.
          Coal ramp rates are 3+MW/min which is plenty across VIC , let alone the NEM.
          Consider VIC’s 1 GW connection to NSW and 0.5 GW to TAS. During high VIC wind they will be exporting and have massive potential to increase relative supply to VIC.

          • Analitik 4 years ago

            If the brown coal generators are that capable, why does this site always talk about them as being “inflexible” ?

            And when wind is generating excess power for Victoria, will NSW want it? SA pricing already goes negative during high wind / low demand periods when they have to export to Victoria. What happens with VIC getting a similar penetration of wind?

            Tas certainly wouldn’t mind negative priced imports to preserve their water levels so they can sell back electricity for a fat profit when the wind dies but they may need to install a lot of pumping stations to make the most of the opportunities.

        • Ian 4 years ago

          Anal itik , gas generators can ramp up and off rapidly, but their gas supply needs are considerable. To make money out of supplying gas the gas distributors need to have their pipelines running to capacity all the time. Do you really think they are going to accept such a huge supply requirement on only a very limited and relatively unpredictable basis?

          • Analitik 4 years ago

            So what will cover the gap between renewable generation and demand when the conditions don’t align?

    • Peter F 4 years ago

      There will probably be a slight change in the balance between CC and OC gas. No matter what the generators do it is in the customers, transmission companies and distributors to install storage. I expect there will be 2-3 GW of storage across SA and Victoria by the time Victoria reaches 40% renewables and Victoria can call on its own hydro + its share of the snowy. Victoria can draw 600MW from Basslink, 1300MW from the Snowy, 600 from its own hydro and about 1500MW from storage about 4GW in all. It has about 2GW of gas, landfill etc so it would still be 2GW short of peak demand if there was no wind and no NSW interconnect. Loy Yang A&B combined can generate more than 3.2GW. If Yallourn is online as well we could even supply about 600MW to SA.

      Peak winter demand in Victoria is around 7.6GW and is falling by about 100MW per year. If Portland closes that will be another 500MW or so. Therefore by 2025 peak winter demand will be below 7GW. SA has more than enough gas to meet peak winter demand so there will not be blackouts. It is merely a question of cost. The more storage there is on the network, the more it favours both combined cycle gas and renewables and the fewer the opportunities there are for price gouging.

      On summer peak days there are always hot northerlies and western Victorian and SA solar will contribute to Victorian peak demand so again in summer if SA, Victoria and Tasmania run together with occasional help from NSW peak demand will be met and annual average supply will be well above 40% renewable

    • Alastair Leith 4 years ago

      You are implicitly suggesting in South Australia as wind generation increased so did gas use. The opposite is in fact the case. What happens when SA finally gets utility storage for dispatch power? No more gaming of the bidding market by gas utility owners?

      • Analitik 4 years ago

        No, I am explicitly stating it. Tell me what fills the gap between wind and solar generation in South Australia and demand when the weather is not cooperative? The Heywood IC is limited to 650MW and only provides that if there are no local network conditions in the east of SA and the west of VIC that limit flows. The “gaming” by gas utility owners has been enabled by the reduction of competition that is directly due to the influence of wind farms on market price volatility.

        Sure, WHEN SA gets sufficient utility storage for dispatch power, THEN there will be no more “gaming” of the bidding market by gas utility owners. Until then, is game on.

        • Alastair Leith 4 years ago

          there’s a much simpler solution, fix up the bidding and settling rules.

          Check out the Melbourne Energy Institute submission downloadable on that page.

          “We broadly support the changes proposed by Sun Metals Pty Ltd (Sun Metals) with respect to aligning the dispatch and financial settlement intervals in the National Electricity market.
          In this submission, we first highlight the importance of ‘fast market’, and argue the current arrangements ‘hobble’ efficient operation of the system.”

          The current mismatch between settlement and dispatch:
          • Diminishes the value of having fast dispatch
          • Encourages sub-economic dispatch
          • Does not provide appropriate incentives for fast response generation
          • Creates opportunities for creative compliance (rebidding)
          In summary, the Melbourne Energy Institute broadly supports aligning the dispatch and financial settlement intervals in the National Electricity Market.”

  3. Kenshō 4 years ago

    “delivery of up to 17 economic and social development obligations. Community ownership (at not less than 2.5% of the total project cost) is mandatory”

    Large scale projects create poor outcomes for social justice. It would be far better to offer incentives for community based investment, like has been done for water efficient appliances, energy efficient lighting and subsidising the cost of solar panels. The same could be done to encourage community investment in PV/storage. This time, instead of giving a disproportionate beginning to the minority and then nothing after, discern a more sustainable contribution to PV/storage for a comparatively greater proportion of the community over a greater span of time, to ensure PV/storage is effectively rolled out with social justice outcomes central. I’m thinking of community buildings, government offices, every sector of the community including residential. This would truly be the distributed paradigm at it’s best, with energy harvest closest to the point of use. It would be more reliable for the grid as a whole, including weather events from wind and fire. It would minimise transmission loses and the cost of poles and wires. It invests in small local business. It cares about and invests in the community instead of big business and private grids.

    • Kenshō 4 years ago

      Very hopeful. This article is along those lines.

      NSW community solar “bulk buy” aims to put 1MW on local homes, business

      I’ve briefly lived and worked in coops and think they’re fantastic. With the technology seeded, I think PV with a bit of storage would be more robust and flexible in a variety of policy environments. Be good if Kangaroo Island formed a coop to coordinate the building of a microgrid.

  4. David leitch 4 years ago

    This link
    compares the proposed Victorian scheme with the ACT scheme.

    Two or three points of interest:
    1. How will the LGC’s be treated? This will impact the LGC price particularly beyond 2020. Views about the LGC price in 2020 will impact project financing decisions today.

    2. There is no requirement to build in Victoria. I think that’s appropriate. There likely will nonetheless be benefits to Victoria from head office location etc.

    3. I wonder about projects that have qualified for ARENA grants under the recent solar round and whether they can be bid in. Or will the “new” generation have to come from projects yet to get the go ahead.

    Looks like the boom in renewable energy is about to restart. Lets go boys and girls.

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