Chapter 1 – South Africa
Connecting the renewables boom to the grid
The focus is on adapting transmission for green energy generation with support from the Government.
The South African renewables sector has benefited from nearly 10 years of what has become a very successful renewable energy development program. The Renewable Energy Independent Power Producer Programme has awarded more than 6,000MW of generating capacity to developers across a range of technologies.
“Developers like the clarity of the process – there is no interference, it’s very reputable and stable,” says Johan Greyling, Energy & Natural Resources Leader – Ernst & Young Incorporated. “As a result, several developers have been in the market for quite some time and have established themselves, with many more trying to enter. So, it is a relatively mature market.” According to Greyling, a number of these participants are global players, and banks have become accustomed to financing these deals, creating an efficient market for renewable energy development in South Africa.
The market has started to become somewhat of a victim of its own success, however, because of a growing connection bottleneck caused by a lack of grid availability. “We now have a glut of renewable resources and a group of very proficient bidders eager to do more at very competitive rates,” Greyling continues. “The challenge will be getting all of them on to the grid while maintaining stability.”
He points out that ongoing efforts to unbundle South Africa’s regulated utility, Eskom, into three businesses covering generation, transmission and distribution could help place more of a focus on adapting transmission to meet current and future renewable generation needs. In November 2020, Eskom published a 2021–30 Transmission Development Plan (TDP) to account for an anticipated reduction in thermal generation (with 11.4GW of coal and 0.3GW of gas set to be decommissioned by 2030) and 26.8GW of proposed new generation capacity – much of which will be “from renewable energy resources that are in areas with limited network capacity,” according to Eskom. In fact, a total of 20.4GW of renewable capacity is expected to be added during the TDP period, and capital expenditure on the integration of renewables is expected to cost ZAR22.7b (US$1.6b).
This indicates the Government’s desire to support further renewables development. As with most markets transitioning from thermal to renewable energy, however, there is a great deal of work to be done.
Chapter 2 – The US
Transitioning to carbon-free energy amid extreme weather events
Grid reliability, public safety and customer affordability are at the fore as net-zero deadlines loom.
In the US, 40 states, including territories, currently have a renewable portfolio standards (RPS) or a carbon emissions reduction target. At the US federal level, one of the milestones set to achieve a global decarbonization economy is to transition to a carbon-free electric grid by 2035. Today’s US energy mix representing 40% is carbon-free from nuclear and renewables generation. Pathways for the remaining 60% of carbon-emissions based power energy mix will require scaling existing commercially viable carbon-free power generation sources and a full array of emerging decarbonization technologies.
US renewables development has surged in recent years to meet this potential demand, but it is proving difficult to connect to the grid system. Of at least 755GW of generation currently stuck in interconnection queues, about 680GW is zero carbon, according to a recent U.S. Department of Energy-funded study by Lawrence Berkeley National Laboratory. The study also estimates that only 13% of this capacity has an executed interconnection agreement. As a result, the US grid cannot move the new power that is coming online to the areas of growing demand. Significant investment in transmission infrastructure, therefore, will be a factor in meeting US emission reduction goals.
The complex nature of the US grid system is a large part of the reason for such bottlenecks. In the contiguous US, the grid is divided into three parts: the eastern and western interconnections, and the Electric Reliability Council of Texas (ERCOT). The complexity goes further than that, however. “Transmission and distribution (T&D) grid development is typically a multidimensional issue because the regulations of how we run the grid vary at a state level,” explains Kimberly A. Johnston, EY Americas Power & Utilities Regulatory Leader.
Contemplating this complex system has also caused stakeholders to begin to consider how to “take their energy into their own hands,” she says. Large power users – such as municipalities, industrial companies and universities – that are concerned about the social and financial devastation of climate change are looking to become “energy islands” by turning hyper-local electricity or electric vehicle networks into distributed energy resources.
“In less than 10 years, the EY organization projects that more than half of electricity customers will become energy distributed resources, operating as an emergency reserve or producing excess capacity that goes back onto the grid,” Johnston says.
These energy islands will still require a connection to an overarching macro grid for regulation and protection against cyber attacks or other risks. As a result, Johnston describes US grid development as progressing along two parallel paths. “One is amending the historical, highly complex, multidimensional regulatory framework,” she explains. “The new, parallel path relates to the need for a whole new ratemaking framework for a customer-centric macro grid, to provide safe, reliable and affordable energy delivery services.”
Like many other parts of the world, the US is also reckoning with the physical impact of climate change on its power sector infrastructure, as well as the need to strengthen and expand the grid to withstand increasingly extreme weather events, such as the disruption caused by Storm Uri and Hurricane Ida in 2021. In Texas, Uri’s impact was most extreme because its grid operates almost entirely separately from the eastern and western interconnections. This means that, while other states can trade power, Texas has very little ability to do so. So, as the storm impacted almost every generation source, the Texas system ran out of power supply options.
There is a heightened awareness of the need to ensure grid reliability, public safety and customer affordability, particularly when we have extreme weather.
Johnston believes the havoc caused by the Texas freeze of 2021 has created a ripple effect among US policymakers and regulators, particularly in light of the rise of renewables. “There is a heightened awareness of the need to ensure grid reliability, public safety and customer affordability, particularly when we have rising extreme weather. And, of course, this is also happening at a time when we need to transition at an accelerated pace to a net-zero carbon grid by 2035,” she says.
While the US grid remains highly fragmented on a state basis, recent federal efforts to address resilience and the need to connect renewables are likely to have a significant impact. A bipartisan infrastructure bill passed by the Senate in August 2021 earmarks US$113b for power and grid-related projects, including those that address reliability and resiliency, as well as the creation of a national Grid Deployment Authority. The package includes other major sectors impacting the grid which includes US$15b for electrification of the transportation sector which will prompt T&D infrastructure investment to prepare for increased electricity demand from EVs as well as the US$25b for the modernization of transit, airports, rail, roads, and safety along with US$65b for 5G fiber deployment to solve the digital divide in communities. The US$21b to brownfield and super fund sites will prompt potential repurpose uses for emerging decarbonization energy sources.
The US Federal Energy Regulatory Commission (FERC), which regulates wholesale power and gas trading and transmission, also launched a consultation on transmission reform in July 2021. It will focus on issues such as improving planning and cost allocation – major roadblocks to transmission development at present – as well as generator interconnection processes. FERC and State Public Utility Commissions have opened hearings and commenced studies on distributed energy resources to assess and determine the forward-thinking regulatory frameworks needed to ensure reliability while progressing towards a customer-centric carbon-free electric grid.
Chapter 3 – Australia
Interconnector to boost renewables after coal plant retirements
The island state of Tasmania will deliver renewable energy storage via an undersea HVDC cable.
Australia’s National Electricity Market (NEM) is navigating a shift to integrate more renewables. The transformation has largely been driven by the National Renewable Energy Target for 20% renewables by 2020, although the driver going forward is upcoming coal plant retirements throughout the market.
“Australia’s situation is quite interesting; although we currently do not have a strong federal policy to decarbonize, our states have renewable energy targets, and the bulk of our coal-fired generation fleet is reaching end of life in the next couple of decades,” says Clare Giacomantonio, Strategy and Transactions Partner, Power & Utilities – Ernst & Young Australia Operations Pty Limited. With the transition to renewables very much underway, Australia’s transmission network needs to be “significantly reconfigured,” she adds. This will be “an expensive challenge” because of the physical size of the grid relative to the load size, as well as the comparatively small number of customers who will pay for any upgrades.
With this in mind, TasNetworks, Tasmania’s state-owned electricity transmission and distribution company, has proposed the AU$3.5b (US$2.6b) Marinus Link. This high-voltage direct current (HVDC) undersea cable would connect the renewables-rich island of Tasmania with mainland Australia. Tasmania, which met its 100% renewable energy target in November 2020 and currently has access to an expected 10,741GWh of renewable energy, has recently raised its ambitions to double that renewable energy by 2040 to become a clean energy exporter. Current resources include wind and significant hydroelectric power, with plans to develop more wind, as well as hydrogen, resources.
“The Tasmanian system is currently almost entirely fueled by hydroelectric generation,” Giacomantonio explains. “The island gets a lot of rain and has some very large dams, and quite a sophisticated hydroelectric scheme with many cascades.” Wind production is also high yield and less correlated to that of the mainland, which adds value in terms of turning Tasmania into a net exporter of energy.
By strengthening the connection between these two parts of the same market, the proposed interconnector would essentially turn Tasmania into a giant battery providing capacity firming services to the NEM. The island would be able to store excess renewable energy generated on-island or transported from the mainland, using this energy itself or returning it to the mainland as needed. Development of long-duration pumped storage hydro on existing dams would further strengthen this role.
A stronger federal imperative to transition to renewables – for example, a carbon price – would reinforce the case to build Marinus Link, according to Giacomantonio. Grid development in Australia’s NEM faces similar challenges to those in other parts of the world, particularly as transmission is usually a regulated asset. This challenges include high standards and lengthy processes for gaining approvals, a regulatory test that was not designed for assessing multiple transmission projects simultaneously to achieve rapid transformation of the grid, issues around cost allocation, and the need to maintain grid stability throughout the transition.
In response to issues related to planning the NEM’s energy transition, a 2017 review of the whole of the NEM resulted in the Australian Energy Market Operator (AEMO) taking a larger planning role. “The regulatory investment test for large transmission projects has been more integrated with AEMO’s modeling in an attempt to streamline the process,” Giacomantonio says. “Whether that has improved efficiency is currently being tested by projects using the new rules for the first time.” Another, more targeted review started in August 2021, and will explore options to further reform or improve regulatory frameworks around transmission planning.
Marinus Link has passed the regulatory investment test for transmission and is progressing toward a 2023–24 investment decision. According to Bess Clark, TasNetwork’s General Manager for Project Marinus, cost allocation remains a key issue, however. “The main challenge to date is the resolution of the current NEM pricing framework for transmission infrastructure, whereby costs are allocated based upon the region (largely Australian state-based) where assets are located, rather than to the customers benefiting from the services.”
When it comes to attracting private investment, Clark believes this issue could cast doubt on the project’s ability to recover all required revenue. Unless there are seen to be fair pricing outcomes, private investors may also have concerns about the reputational and project risks around funding a project without strong community support.
“The investment test has demonstrated that the project provides net benefits to the NEM, but the current pricing/cost allocation frameworks need to be resolved before the project can proceed as a regulated service,” Clark says. “The methodology used to allocate transmission costs between NEM regions and between generators and load customers is, therefore, coming under greater scrutiny, with ongoing energy minister discussions on a way forward.”
If Marinus Link does go ahead, it will also provide an avenue for Australia’s hydrogen ambitions. Tasmania, in particular, provides a solid use case, given its 100% renewables status. “A number of green hydrogen proponents are active in Australia,” Clark says. “Marinus Link complements hydrogen opportunities by supporting continued development of variable and dispatchable clean energy resources and supporting transmission at lowest cost, as well as providing additional resilience in the national power system. This enables hydrogen investors to have greater confidence in the adequacy of their clean energy supply.”
Chapter 4 – The UK and Europe
Connecting markets and supporting future hydrogen development
Storage, offshore wind build-out and interconnectors will help manage increased renewable generation.
Hydrogen is likely to play a key role in the UK’s efforts to decarbonize its power system by 2050. As renewables output increases, green hydrogen production could support grid flexibility by providing storage solutions for excess generation. In its August 2021 Hydrogen Strategy (pdf), the UK Government said such solutions would provide a wide range of system benefits, as well as an additional route to market for new renewables capacity. “Coupling this electrolytic hydrogen production with storage, including long-duration storage where hydrogen is a lead option, can help integrate hydrogen further into our power system by helping to balance the grid when generation from renewables is higher or lower than demand,” the report states.
While such hydrogen-based solutions remain in the early stages of development at present, the UK’s electricity regulator, Ofgem, is already laying the groundwork for the much-needed redevelopment of its grid. According to Iain Cameron, Chief Operating Officer of Frontier Power, Ofgem is seeking to attract more investors and encouraging innovation through increased competition. “In our view, as participants in this process, this has been successful in bringing in new sources of finance and driving project development at a faster pace than the incumbent grid companies would have done so on their own accord.”
In addition, the UK needs to connect its burgeoning offshore wind market to the grid. As a world leader in this market, the UK is well on its way to meeting its target of 40GW of installed offshore wind capacity by 2030 – the project pipeline reportedly surpassed 50GW last year. This sector is also likely to support the future development of hydrogen production, with several North Sea projects already planned.
“The grid needs a lot of new investment to enable these connections along the coastlines, so there is a challenge as to how to achieve a competitive market for this development,” Cameron adds. “Ofgem is trying to encourage more coordination between offshore and onshore network development to facilitate more efficient network build-out to enable energy transition and offshore renewable energy. That’s going to require more central facilitation than there has been in recent times.”
Interconnectors not only support the convergence of average energy prices between markets, but they are also particularly effective in smoothing the increasing volatility in supply and energy pricing.
In addition to the offshore wind build-out, interconnectors will be needed to manage the variability of increased renewable generation in the UK and throughout Europe. As the UK moves away from a thermal power system in which supply and demand can be balanced in a controlled way, these connections will enable power to be traded between markets.
“Interconnectors not only support the convergence of average energy prices between markets, but they are also particularly effective in smoothing the increasing volatility in supply and energy pricing, as renewable penetration increases,” says Humza Malik, Founder and Chief Executive of Frontier Power. “Interconnectors are only one part of an overall solution that will include storage, interconnectors and different types of renewable generation.”
In the UK Government’s December 2020 Energy White Paper (pdf), it pledged to work with Ofgem, developers and European partners to increase 18GW of interconnector capacity by 2030. The paper states: “This represents a three-fold increase from current levels and will position us as a potential net exporter of excess green energy, helping to keep wind turbines generating even when GB electricity demand has been met.”
Both the European Commission and the European Council support a 15% electricity interconnection target for EU members, with a Commission study estimating that an integrated European energy market could save citizens €12b–€40b (US$14–US$48) annually by 2030.
Frontier Power is engaged in several interconnection projects, including NeuConnect, a proposed 1.4GW “invisible highway” that would connect the GB and German power markets. In this new competitive environment, Malik says organizations such as Frontier Power and its partners are working to accelerate the pace at which such solutions are implemented, including introducing new sources of finance and project innovation. Independent developers will be critical in bringing about the sort of infrastructure development needed to help meet ambitious decarbonization goals at pace.
The role of grid investment in the global energy transition
Given the extent of grid development needed across the globe, it will be crucial for all regulators to reconsider the permitting, regulatory and financing environment to help ensure outdated grid systems do not become a major hurdle in the race to net zero.
Many markets are already aware of this need, and some are even working on solutions in a bid to streamline these processes. As demand for renewables capacity continues to increase, such efforts will be necessary to attract much-needed investment and follow the net-zero pathways laid out by governments around the world.
As renewable energy generation flourishes around the world, grid infrastructure will come under increasing strain. A 50% rise in global grid spending could be needed over the next decade to meet long-term sustainability goals, and transmission companies will have to rethink their operations and business models. Integrating growing volumes of variable resources will require a new approach, particularly in markets built around thermal power generation – so different markets are having to adapt their grids for a carbon-neutral future.