On June 8, 2015, Hawaii became the first state in the nation to commit to converting its electric power supply to 100% renewable energy, with a deadline set for 2045. This goal challenges the state to tap its plentiful, natural, clean sources of power, while its utilities must build grids, interconnection infrastructure, and business models that will make these power sources accessible and affordable.
Investor-owned utility Hawaiian Electric Co. provides power to 95% of residents on five of the state’s six main islands: Hawaiian Electric Co. itself serves Oahu; its Maui Electric subsidiary covers Maui, Molokai and Lanai; and a second subsidiary, Hawaii Electric Light, serves Hawaii Island. In this article, “Hawaiian Electric Co.” will be used to refer to the investor-owned parent company, and “Hawaiian Electric utilities” will be used when referring to the parent and its subsidiaries collectively.
As of December 2016, the Hawaiian Electric utilities had, on average, achieved 25.8% of the state’s renewable energy mandate. The utilities’ power mix now encompasses customer-sited private, rooftop solar systems and grid-scale technologies, including wind, solar, geothermal, biomass, biofuels and hydroelectricity.
Increasing levels of customer-sited rooftop solar PV have created a surplus of daytime, non-dispatchable generation on all of the Hawaiian islands. The Hawaiian Electric utilities cannot directly control this behind-the-meter generation, which is effectively “must take” power. As a result, they must manage other generation resources – conventional or renewable, company-owned or private – around the output of these rooftop solar systems.
Thus, at times when an island’s grid does not have sufficient demand for all of this PV production, the utility serving that island must reduce to a minimum or turn off some of its generation – by curtailing power from utility-scale wind and solar projects – in order to maintain grid stability and reliability.
To reach the state’s goal of 100% renewable power by 2045 – and its interim goals of 30% by 2020, 40% by 2030 and 70% by 2040 – Hawaiian Electric Co. has begun to develop better ways to manage curtailed power, which otherwise is lost to the system.
Part of the solution can be found in a report the company recently filed with the state’s Public Utilities Commission (PUC). Authored by the Smart Electric Power Alliance (SEPA) and ScottMadden, the report outlines a new model power purchase agreement (PPA) that Hawaiian Electric Co. is now preparing to use for future utility-scale renewable projects.
As principal co-authors of the report, our ultimate goal for this new model PPA, called the Renewable Dispatchable Generation (RDG) model, is to convert utilities from passive takers of power generation produced by various sources into proactive asset managers. With the RDG, curtailment, if necessary, is scheduled based not on the seniority of projects – that is, the most recently commissioned projects are curtailed first – but on specific, real-time needs and costs to the system. Production by these projects is then reduced in a way that creates “headroom,” or a reserve of power, that can provide ancillary, grid support services such as frequency or voltage regulation or spinning reserves.
The RDG model also improves project economics by allocating the risk of potential revenue loss due to curtailment more equitably between renewable energy developers and utilities.
Concerns related to curtailment are not unique to the state of Hawaii. The issue has emerged in California and other states where high levels of distributed solar PV have resulted in potential curtailment of other large, lower-cost renewable assets. However, because each Hawaiian island has a grid with no interconnection to others, on top of a residential solar penetration level of more than 20%, the state far outpaces others in the magnitude of curtailment necessary to balance supply and demand.
Curtailment issues
Electricity prices in Hawaii are among the highest in the U.S. – more than twice the national average – which has given customers a compelling incentive for deploying private rooftop solar and other distributed energy resources (DERs), such as storage and electric vehicles. Hawaiian Electric Co. is forecasting that levels of customer-sited DERs on island grids could almost triple by 2030.
At the same time, the utility is planning to significantly increase utility-scale wind and solar generation on each island. Because behind-the-meter DERs meet a large portion of each island’s electricity use, the load served by utility-scale conventional and renewable resources is increasingly limited during peak sunshine hours. The result is the potential for a growing need for curtailment.
At its most basic, curtailment is the reduction of a given purchased power resource below its otherwise theoretical output level. Since variable renewable resources like wind and solar are not dispatchable by nature, their production profile cannot be modified to meet system needs without forfeiting energy production. And because each island has its own, self-contained grid that can neither import nor export power, the potential need for curtailment could be significant.
It is expected that midday distributed solar generation in Hawaii will continue to increase, which may mean that a greater percentage of new grid-scale projects (including potential community solar projects) may likely face curtailment. Without some form of mitigation, we believe that curtailment levels on Oahu could conceivably reach 10%, while estimates for curtailment on Maui and Hawaii Island range from 20% to 50%.
Traditional PPAs handle this risk in one of two ways. In the first, the utility compensates the project developer or independent power producer (IPP) only for the power actually delivered, and the uncertainty resulting from any curtailment must be absorbed by the developer or IPP. In the other – sometimes called a “take or pay” contract – the utility pays for any energy that is produced or could have been produced if not curtailed.
Either way, the dollars-and-cents impact is higher prices, with the cost of curtailment ultimately passed to customers. Specifically, developers today must account for curtailment risks within their PPAs. A utility-scale plant that would normally be priced at $100/MWh might compensate for a 20% curtailment risk by bumping up its price to $125/MWh. The higher price raises costs for utilities and customers, increases potential losses for curtailment, and may make projects harder to finance.
The RDG model: How it works
The RDG model for PPAs aims to provide renewable dispatchability while integrating high levels of DERs. Under these contracts, the utility can schedule a percentage of potential production from a renewable project, based on solar or wind resource availability on any given day, factoring in the needs of the system from both a cost and reliability perspective.
Under ideal circumstances, the contract would require a solar developer or IPP to do the following:
• Guarantee minimum availability metrics to ensure the equipment is maintained and available for production;
• Meet technical and operational characteristics that support grid operation, including voltage regulation, disturbance ride-through, frequency response, and active power control; and
• Provide an indication to the utility of the available energy in near-real time.
These guarantees form the basis for the energy production – or megawatt-hours – expected for a given solar irradiance or wind speed. The utility, in turn, controls the real and reactive power output of the facility on a real-time basis. From an economic standpoint, the utility pays a fixed monthly amount to ensure the system is financeable, and a variable component, in dollars per megawatt-hour ($/MWh), to cover operations and maintenance costs – if applicable, depending upon the resource.
Any unscheduled energy, up to the amount capable of being produced given existing weather, becomes spinning reserves – unloaded generation that can be called upon in minutes. The power can also be deployed automatically, according to defined frequency response parameters.
Traditional curtailment order – under which the newest projects are curtailed first – would also be changed for new projects going forward. Under the RDG model, curtailment order would be based more closely on economics and system needs than on the date of first operation. For standard agreements, the PPA price is the most logical trigger for curtailment order, with flexibility outside of economic dispatch based on specific local system needs.
For example, Figure 1 shows an average day’s production for a solar plant with a nameplate capacity of 10 MW.
Under the RDG structure, the utility intentionally dispatches the resource at 50% production. Later, due to greater demand, the utility increases the production to 100% in the late afternoon, as shown in Figure 2. The ability to ramp up that solar asset could create more than 3 MW of upward spinning reserves on this average day, with over 2 MW of increased generation actually leveraged between 3 p.m. and 4 p.m.
This project could also provide downward spinning reserves during all producing hours. Alternatively, that same unloaded generation could be used for regulation purposes, with inverters varying output based on the system frequency at any given moment. By purposefully under-scheduling the solar asset, the solar generator can contribute to the provision of ancillary services.
Historically, variable renewable resources have not provided these types of grid services. Adding the ability to provide spinning reserves and frequency response reduces the integration costs of adding these assets to the system, effectively increasing their overall value to the Hawaiian Electric utilities. With the utilities’ push toward a 100% clean energy future, these added capabilities may become critical to system reliability.
On the financing side, the RDG model provides guaranteed revenues – assuming the minimum requirements for a project’s availability and energy production potential are met – which should result in more certainty around debt service coverage and equity returns. Risks are therefore more equally shared between utilities and IPPs.
Looking ahead
Challenges remain in transitioning directly to this new contract structure from today’s paradigm. Several iterations may be needed to refine resource forecasting and associated availability metrics and to overcome any additional operational challenges.
Research is ongoing into how customers may be affected by these new agreements. Potential unintended consequences as a result of increased fixed payments and the curtailment conditions need to be identified and further discussed.
Moving from concept to execution on this new model will also require a reshaping of utility procurement processes. Rather than focusing primarily on the lowest price for delivered energy, procurement will need to balance multiple pricing and delivery options against long-term price risk for consumers. IPPs, regulators, utility companies, and other major stakeholders will need to work together to determine how future requests for proposals will be designed. In particular, IPPs must have a clear picture of how projects will be valued, and utilities must be able to receive clear, transparent and detailed information from developers to expedite the review process.
All stakeholders will also need to agree on how to translate these new ideas into contract language. The procurement team at Hawaiian Electric Co. is now developing this language. The utility has yet to submit a project using this revised PPA for PUC approval.
Fast-evolving technology – such as energy storage – is another key variable. Hawaiian Electric Co. has already begun researching the potential for energy storage to provide fast frequency response.
This and other applications for energy storage warrant further discussion and research, as the best solution for Hawaii is most likely a holistic package of customer, developer and utility investments that are collaboratively planned. Such considerations can be part of a robust integrated resource planning process that weighs the relative pros and cons of different resources and contract structures for the benefit of all customers over the long term.
Whatever solutions are found in Hawaii will undoubtedly have a ripple effect for other U.S. utilities as they confront rising levels of solar on their distribution and transmission systems. Although the diversity of U.S. markets requires locally customized models, the message is clear: The grid of the future is evolving out of the existing system, creating a hybrid in which traditional utility and solar business models must also transition. Proactive, collaborative innovation is the new normal.
John Sterling is senior director of research and advisory services at SEPA. He can be reached at jsterling@sepapower.org. John Pang is a partner at ScottMadden, and he can be reached at johnpang@scottmadden.com. This article draws from a SEPA-ScottMadden report titled “Proactive Solutions to Curtailment Risk.”
Other Options To Mitigate Curtailment Risk
The Dispatchable Renewable Generation model for utility-scale solar PPAs is one of three potential approaches to curtailment explored in the SEPA-ScottMadden report, titled “Proactive Solutions to Curtailment Risk.” The other two models are the following:
Capacity and Energy PPAs: For these contracts, bidders would propose pricing based on two components: fixed ($/MW per month) and energy ($/MWh). Bidders would incorporate their curtailment risk outlook into the proposed breakdown between fixed and variable components. This approach provides a guaranteed income stream for developers while also reducing risk for utilities and their customers.
Time-of-Day-based PPAs: These contracts would be based on energy prices being lower (or negative) during expected low-load periods and higher during peak-load hours. Price caps would be set for every hour of every day of the year, taking into account seasonal variations. The uncertainty of predicting the long-term system load profile makes this option difficult to align with forecast production costs and, therefore, appropriate energy prices. Setting up and administering these contracts would also be extremely complex.
