Developing the 2021 Integrated Resource Plan: Tough Choices Ahead for Government & BC Hydro

INTRODUCTION

The BC Government has instructed BC Hydro to undertake a new Integrated Resource Plan (IRP), to be filed by February 28, 2021. The release of a new IRP, the first since 2013, will guide the energy resource planning process in the Province for the coming years. In this IRP, BC Hydro’s mandate is to provide a description of its forecasted energy and capacity requirements. Additionally, BC Hydro’s mandate will be to describe their plan to satisfy these requirements, while adhering to the self-sufficiency and environmental mandates set forth by the Clean Energy Act (the “CEA”).

Given BC Hydro’s most recently available capacity load resource balance forecasts, from their F2017-F2019 revenue requirements application, it can be confidently assumed that a key challenge in developing the next IRP will be overcoming an impending capacity shortfall. This challenge will only be made more difficult by both impending industrial development in Northern BC and the restrictions imposed on BC Hydro’s resource generation options by government through the CEA. The former adds future load uncertainty to the equation, while the latter restricts the possible ways BC Hydro can meet growing demand. This paper analyses the challenges facing BC Hydro and Government in developing the next IRP, considers the influence of the British Columbia Utilities Commission (the “BCUC”), and discusses the potential outcomes and key implications of the IRP development process.

BC HYDRO’S FORECASTS

BC Hydro’s most recent capacity load resource balance forecast can be found in the utilities’ F2017-F2019 revenue requirements application (“RRA”). These forecasts contemplate supply side capacity resources and future demand, while considering projected demand side management (“DSM”) measures. It is critical to note that the ability of BC Hydro to succeed with these ambitious DSM measures deserves to be questioned. However, even if the entirety of the anticipated savings from the 2016 DSM plan are taken into account, BC Hydro’s own modelling projects a capacity shortfall in 2023. The model projects this shortfall to be temporarily eliminated in 2025 as greater DSM savings accrue and Revelstoke 6 comes online. However, by 2029 a capacity shortfall returns and is projected indefinitely. 

BC Hydro has since released the F2020-2021 RRA. This review does not include an updated capacity specific load resource forecast. However, it does provide the most recent energy load forecast based on projected sales. In this latest forecast, increasing energy demand in the province is projected moving forward. 

The ramification: BC Hydro, by its own accounts, will require more capacity shortly, and its options are limited. Moreover, these models pre-date Government’s CleanBC initiative and thus do not fully take into consideration the necessary electrification of industry in order for BC to meet its regulated GHG targets, and the effect this will have on future demand. 

THE MAJOR PLAYERS

Developing the IRP in this context will not be easy. BC Hydro is not the only key player involved in the process of drafting the next IRP. In addition, Government and the BCUC will both assume leading roles. 

To analyse the roles of the major players, and the implications of their involvement, it is critical to consider what the process of IRP development will look like. BC Hydro is tasked with undertaking the development of the IRP, forecasting their energy and capacity needs, and describing how these are to be satisfied. They are instructed to do this by Government, who also set the rules by which BC Hydro must abide through legislation, specifically the CEA. Finally, as BC Hydro is a regulated utility, the IRP must be submitted to, and approved by their regulator, the BCUC.

For BC Hydro, the aim is to add capacity. The CEA limits their options. Specifically, it explicitly prohibits several generation methods that would add reliable capacity in addition to energy. Section 2(o) prohibits the use of nuclear power. Section 10 severely limits the ability to construct storage hydro projects not on the Peace or Columbia rivers and explicitly prohibits a number of hydro projects. Section 13 bars BC Hydro from using the 900MW Burrard Thermal generating plant in its resource planning.

Restrictions on generation resources are not the only consequence of legislation. Additionally, Section 6 introduces the self-sufficiency mandate which rules out BC Hydro signing import contracts to meet capacity needs. Other constraints in the CEA, such as Section 2(c) which requires 93% of the electricity generated in BC to be from clean or renewable sources, highlight the influence of Government legislation on the process. BC Hydro cannot draft an IRP that intends to meet future capacity needs through any of the prohibited means or from non-renewable sources in a way that violated the CEA. This would not be acceptable to Government.

The BCUC will review and ultimately approve or modify the application provided by BC Hydro. The BCUC’s mandate is to regulate public utilities in the Province and manage the rates charged by these utilities. It is reasonable to expect that the effect of BC Hydro’s plan on ratepayers would be of principle concern to the BCUC. Therefore, they will likely look sceptically towards any plan that would have an adverse effect on rates. Renewable energy solutions generally carry high capital costs, posing a potential source of friction in the proceedings. As a result, drafting a plan acceptable to the BCUC is another major challenge. 

The product of all these factors is a very difficult situation to navigate. In a world where it is assumed that Government will enforce the directives set forth by the CEA and that the BCUC will strictly follow its mandate, BC Hydro will need to find solutions that allow the utility to (1) cover an impending capacity shortfall; (2) not violate the directions or objectives set forth by Government; and (3) create a plan that will not result in drastic rate increases and is thus acceptable to the BCUC and to Government.

SUPPLY OPTIONS

BC Hydro has tended to approach the supply problem by focusing on cutting demand through savings attributed to DSM measures. However, BC Hydro’s own model, and our analysis, highlight the fact that these measures alone will not be enough. BC Hydro will need to actively address the problem through the addition of new generation resources.

The utility has previously floated the idea of constructing gas peakers. These systems would be able to be utilized during times of peak demand. For a number of reasons, however, this is not an ideal solution. First, gas peakers generate electricity by burning natural gas and therefore emit greenhouse gases. With government imposing the 93% clean or renewable standard, this does not appear acceptable. Second, while they can be well suited to regional needs, or to address “needle peaks” in demand, gas peakers are not suited to use in a system with broad-based capacity needs, for both environmental and cost reasons. 

Ideally, BC Hydro would pursue a generation option that is simultaneously clean and capable of providing both energyand capacityat the same time. Unfortunately, a review of renewable energy sources reveals few candidates. Wind, run-of-river, hydro, and solar provide energy but not reliable capacity. Two renewable options, however, geothermal and biomass, merit stronger consideration. 

Geothermal power is unchartered territory in BC and Canada. But the technology is appealing, since unlike most other renewables, it provides both a source of energy and capacity. Estimates of the amount of geothermal potential in BC vary, but range between 200-600MW of economically feasible capacity. Installing this magnitude of geothermal power could be an avenue by which BC Hydro works towards satisfying its capacity needs while also meeting Government’s environmental objectives. Further study would be necessary to accurately assess the effects on electricity rates. 

Biomass is another resource option that is both renewable and a reliable source of both energy and capacity. Biomass generates electricity from the combustion of organic material. In BC, the commonly used organic material is wood, often waste products from sawmills. Given BC’s geography and active forestry industry, there is theoretically a significant supply of available wood fuel for biomass generation. In the 2013 Resource Options Report, BC Hydro’s findings showed upwards of 1000MW of potential installable biomass capacity in the province.

The biggest problem associated with biomass is concerns over long-term fuel availability. While BC has ample wood resources, this does not necessarily ensure a reliable fuel supply for biomass generation. As the 2013 BC Hydro report states, there are many competing uses for these resources. If the available resource fuel for biomass generation is less than anticipated this means the capacity potential of biomass would be similarly lower.

Given that the optimal fuel source for biomass generation is not standing trees but rather waste products from forestry operations, it is ideal for biomass generation facilities to exist in close proximity to sawmills. This concept can already be seen in practice in BC. The 36MW Conifex Timber Green Energy Facility in Mackenzie, for example, is located proximate to the company’s Mackenzie sawmill. Such an arrangement ensures stable fuel supply because of the forest companies’ interest in ensuring the generation plant remain operational. However, in less synergistic arrangements there is always the risk that the supplying sawmill shutters operation. In such a scenario, a biomass facility would need to find a new source of fuel. This could mean waste from a distant mill or from standing timber at ever increasing distances from the plant. Regardless, there would be an increase in costs. Given the high capital cost of building generation facilities, the reliance on sawmills with uncertain futures presents risk.

Another option is a set of renewable assets such as wind or solar that work together to provide reliable capacity. While a single wind or solar plant, for example, is unable to serve BC Hydro as a source of dependable capacity, a linked system theoretically could.

The viability of a system of this nature would depend on industry co-operation. Development of a linked system would require co-ordination to identify and develop the renewable projects that when “linked” would provide a source of reliable capacity. To date, BC Hydro has been unwilling to provide the necessary incentives to drive corporate behaviour towards this end. However, were this protocol to change, and BC Hydro were to provide strong enough incentives to industry, it is conceivable that a linked system of clean energy could be relied upon to provide a degree of additional dependable capacity to the BC grid. 

IMPLICATIONS

When BC Hydro’s load forecasts, the key players in the IRP process, environmental legislation, and supply options for reliable capacity are considered, the only certainties that can be drawn are the impending need for additional capacity that is clean and renewable, and the fact that BC Hydro is in a difficult position.

While the burden of drafting an IRP falls on BC Hydro, this process will be greatly directed by the actions of Government. Broadly, the Province can follow one of two approaches moving forward. 

A first option would be for Government to amend the CEA. As this paper has outlined, legislation has painted BC Hydro into a corner with limited options by which to attack the problem. It is fair to argue that the CEA, in its current form, is overly restrictive. Changes to the CEA could occur in a number of forms. 

A common suggestion is to remove the self-sufficiency mandate, a move which proponents argue would allow BC Hydro to pursue a new source of capacity, the market. While there is merit to the debate over whether to repeal self-sufficiency, the notion that trade alone could solve BC Hydro’s capacity shortfall suggests a false solution. This is due to the nature of how electricity markets transact. These spot markets, such as the Mid-Columbia (“Mid-C”), for example, clear (most hours) at the short-run marginal cost (“SRMC”). This cost represents a price which covers the variable cost of the producer and makes some contribution to its fixed costs. The power that flows into Mid-C, and clears at this price, is largely the hourly surplus from plants in the region. Logically then, surplus energy selling at the SRMC will be available relatively cheaply. While this represents a potential source of energy, hence the merit to the self-sufficiency debate, it is not a reliable source of capacity, which BC Hydro needs. Relying on other utilities to constantly supply a surplus of energy available for cheap is not a sustainable long-term resource planning strategy for BC Hydro. The absence of guaranteed supply rules this out as an option. 

Amending other aspects of the CEA, such as the 93% standard, or the various prohibitions on generation options, could be an option for Government. Such a shift would give BC Hydro more resource planning options to add additional capacity. However, Government may find that moving to allow new hydro projects or walking back on its stance on natural gas generation, for example, is politically unpalatable. Approving Site C was already contentious. Repealing or amending environmentally focused legislation in order to allow new dams or non-renewables so soon after Site C’s approval is likely a scenario this government wishes to avoid. 

If Government opts not to make changes to the CEA, BC Hydro will need to embrace one or more of the supply options described in this paper, with the heaviest reliance on biomass and geothermal.

Geothermal has marked untapped potential, but the barriers to its inclusion in BC Hydro’s portfolio are strong. The use of the technology would be a first in Canada, and the associated costs are steep. More than likely, the financially workable path to geothermal development would involve two fundamental changes to current practice. First, BC Hydro’s procurement approach would need to change, to reflect the up-front risk of geothermal and its ability to deliver capacity as well as energy. Second, a broader commitment to large scale geothermal development would need to occur. This work would be challenging, but the option is there.

Biomass, conversely, already exists in the Province. The technology is not free of problems but its path to expanded implementation is much simpler than geothermal. Further, major steps could be taken to mitigate the issues with biomass. For example, deeper co-operation with industry and specifically forestry companies could work to negate the fuel supply issues associated with biomass. Incentivizing construction of more plants like the one in Mackenzie, for example, could be a model that is pursued. Minimizing risk would allow BC Hydro to focus on extracting biomass’ value: a clean, renewable source of both energy and capacity that works to eliminate BC Hydro’s pending capacity shortfall while being compatible with Government’s environmental goals.