Battery storage co-located with a solar PV plant would enable grid services such as dynamic containment, besides mitigating the profitability risks that arise from excess supplies in the grid. Project pipelines in major battery storage markets, such as the US and UK, show a progressively rising interest in solar-plus-storage projects. The relatively higher investment returns in such projects potentially outweigh the complexities (such as separate permits, feasibility studies, etc.). Some investment funds have also adopted the retrofitting route in battery colocation. In 2023, NextEnergy Solar Fund initiated retrofitting of storage to its solar PV portfolio for better returns. Grid uncertainty is potentially one of the major driving factors in the colocated solar projects. It may partially solve the more significant and fundamental problem of grid connection request queues.

Globally, solar power projects in some of the leading power markets drive the pile-up in developers’ grid connection requests. Shorter lead times in the commissioning of solar power projects make it even harder for the TSOs to arrange connectivity in an already congested grid. At least in the near to medium term, solar power pipelines may aggravate the issue. It may also enhance the role of storage in grid flexibility.

Various projections point to an investment outlay of $400 billion in the global transmission project pipeline over the next 5-10 years. The investment quantum and its schedule may change with time. For stakeholders, especially investors and developers, the pointers lie in the capacity additions that suggest possible easing in bottlenecks. There might be a mixed picture in this regard. For example, BNEF’s Net Zero scenario entails doubling the global annual grid spending by 2030. A few markets (such as California ISO and the UK) make the cut in this parameter. Most of the other markets are lagging in the investment levels aligned with net zero goals fixed by the respective authorities. In effect, the TSOs’ grid development plans are about managing the rising network demands. The demand drivers are essentially the same for all transmission utilities, especially those in advanced economies. Among the most discernible pressures on TSOs and system operators is the addition of renewable power capacity and the grid connection queue it causes. In the US market, this is likely to persist for some time. As of April 2024, about 2.2TW of generation capacity, a multiple of the whole country’s installed power generation capacity, was in the queue for pending grid connection. (S&P Global, 2024).

Despite the gradual improvement, it will be a long way to ease the crunch. In the European markets, the lack of timely capacity often manifests in grid curtailments or even the occasional pause for new grid connection requests. Globally, grid curtailment has risen in the high renewable energy penetration power markets, such as in the California ISO, Germany and the UK. The impact on renewable projects can vary. In Germany’s framework, for instance, there is total compensation for curtailment. In Texas, there is none. Worsening grid congestion could also hinder the growth of power market transactions. Cross-border transmission links, as in the European Union, could significantly contribute towards renewable energy-led interconnected power markets. The planned transmission hub in the North Sea region underscores the untapped potential.

In the US market, transmission projects have been prone to increasing delays. In 2023, just about 250 miles were commissioned, whereas an average of 2,000 miles were installed between 2012 and 2016 (Business Insider, 2024). A fragmented business and limited coordination led to such a pass. Some recent policy and regulatory measures aimed at sorting out the logjam may address it. For instance, the US Federal Electricity Regulatory Commission (FERC) directed the regional grid operators, states, and utilities to develop 20- year transmission plans to meet the upcoming demand and an agreeable way to pay. FERC’s same directive also made it harder for the states to back out of the commitments.

Implementing comprehensive and systemic changes in transmission project implementation will take much longer. Examples of constraints in the US market are also seen in European projects. With multiple stakeholders and jurisdictions involved, it is often beyond TSOs to compress schedules. An example in point is the construction of the 340km HVDC link of Ultranet in Germany, which requires 13,500 permits. (BNEF, 2024). Incidentally, over a quarter of the European transmission projects marked as projects of common interest for priority funding also face delays primarily due to the permitting procedures. (IEA, 2023).

Permitting and procedural processes will likely be subject to the same pressure points in the near term as they have been over the past years. In comparison, emerging market economies, especially China and India, have much shorter lead times, on average, in commissioning transmission lines. Centralised decisions and interventions (e.g., dedicated power evacuation corridors) have recently been among the most critical factors. Comparable measures in advanced economies could be traced to the steps undertaken towards facilitating private investments (merchant lines in the US or the OFTO regime in the UK) to expedite projects in select sub-segments. However, investors and developers must factor in the inherent uncertainty involved in the transmission project pipelines.

The spike in grid capex is forcing a rethink about incentives. There are some early signs that the TSOs may find acceptance for revised grid rates. As of August 2024, two system operators of the US, namely, the Midcontinent Independent System Operator (MISO) and the Southwest Power Pool (SPP), sought federal regulators’ approvals for proposed changes in the tariff structure. The tariffs would help advance $1.7 billion in investments and enable 30GW of new generation capacity (Utility Dive, 2024). Similarly, many other US and European utilities have rate revision requests in the queue before the respective authorities to match mounting capex requirements. The justification for the tariff revision is more substantial than before. In Germany, the network operator’s announcement on revised grid tariffs of 2024 was followed by a government subsidy worth €5.5 billion to help minimise the impact on end consumers (Clean Energy Wire, 2023). Regulators in Austria and Switzerland have similarly authorised higher grid tariffs (Scope, 2023).

The higher tariffs may just help catch up with the past years of lagged tariff revisions. Meanwhile, TSOs must manage the rise in development costs due to logistics, material supply chain, and wages, among other things. The recent softening of interest rates worldwide may help utilities planning to raise debt capital. Many have had to postpone their borrowings earlier, as higher costs vis-à-vis approved returns posed a barrier. In addition, non-core asset disposals help expand the avenues for TSOs to channel financial resources. More utilities are expected to join the fray in non-core asset disposals to mitigate balance sheet pressures amidst weak credit ratings.

To a significant extent, the respective governments and policy authorities may also be responsible for supporting the transmission capex. Policy-level action may take varied forms, not just direct funding support, as seen in Germany. Enhanced private participation and enabling market entry for competition are two avenues through which policy action could drive investment spending in the business.