(January 3, 2018) The OEB has issued its decision on OPG’s multi-billion dollar, five-year rate application. Here’s what you need to know.
The Ontario Energy Board (OEB) recently issued its decision on Ontario Power Generation’s (OPG) application to set rates for power generated at its nuclear and hydroelectric facilities between 2017 and 2021. It was the largest application ever reviewed by the OEB, amounting to $16.8 billion in costs to maintain and operate OPG’s nuclear fleet and more than $6 billion relating to its hydroelectric facilities.
We break down the major points in the OEB’s decision.
1. OPG’s management failures are apparent in two nuclear projects. The OEB took OPG to task for its management of two nuclear projects – the Auxiliary Heating System (AHS) and the Operations Support Building (OSB). In total, the OEB says OPG will eat $33 million in costs related to those two projects. It’s easy to see why. The original price tag for the AHS project was $36.3 million, while the final bill totalled $107 million – a 194% increase. The OEB highlighted extensive audit reports (submitted by OPG as evidence) that detailed the poor management of this project and others that have suffered more dramatic cost escalations. It was a similar story with the OSB, which was initially expected to cost $29.7 million, but will come in at $62.7 million – a 111% increase. The OEB concluded that such a dramatic cost increase is “not reasonable.”
2. OEB calls for an audit of problematic division at OPG. Both the AHS and OSB projects were overseen by a particular division within OPG, known as the Projects and Modifications (P&M) organization. A number of audit reports of the P&M organization (noted above) detailed a breakdown in contracting, oversight, cost estimates, schedules and a failure to adequately get projects back on track. The OEB concluded there is “room for improvement” at the P&M organization and that the utility should conduct and file an audit of P&M that examines “adherence to best practices, measures and reporting regarding cost and schedule performance, and implementation of lessons learned.” It should be noted that another project overseen by P&M, a heavy water facility, has since been found to be hundreds of millions of dollars over budget. OPG removed the project from its application – mid-way through the rate application – due to delays and cost uncertainty.
3. OEB slashed $100 million annually from OPG’s nuclear operating costs. OPG’s annual cost to operate its nuclear plants totals more than $2.8 billion annually. The OEB said those costs are excessive, given the utility’s high compensation rates, particularly in regards to the pensions on offer to its employees, and its poor performance when benchmarked to other nuclear plants across North America (see below). The OEB warned that OPG’s pension costs continue to be “well in excess” of its comparators. As such, the OEB has ordered the utility to cut $100 million, or $500 million over its five-year application, in operating costs.
4. OPG fares poorly when compared to other nuclear plants. The OEB noted that OPG has been benchmarking the performance of its nuclear plants to those across North America since 2008 and has, over that time, posted “very poor” results. The regulator said that poor performance has been a “concern” for nearly a decade. “Since 2008 its ranking for each of the three key metrics has been either at or near the bottom in every year,” the OEB said in its decision. “Both the OEB and OPG expect better than this, and ratepayers should expect better too.”
Worse still, while OPG blames its poor ranking on one-time maintenance issues and early, less efficient reactor designs (in the case of Pickering), the OEB rightly pointed out that OPG can’t even hit its own targets, which would include those discrepancies. The OEB also detailed the many internal targets that OPG set for itself and then, subsequently, failed to achieve. The OEB also warned that OPG’s benchmarking results are likely to get worse in the next five years.
5. OEB calls for a higher stretch factor. Regulators often apply an annual “stretch factor” to utilities, which is intended to incent productivity improvements (and lower costs for consumers). A utility may be expected to lower its costs by 0.5% annually, for example. The higher the annual stretch factor, the more savings, or efficiencies, the utility is expected to find. In its application, OPG argued that it should be given a 0.3% stretch factor and that it should only apply to its nuclear operating costs (capital spending would be excluded). The OEB, largely citing the utility’s poor benchmarking results and excessive operating costs at its nuclear plants, thought otherwise. It assigned a 0.6% stretch factor and said it should apply to both nuclear operating and capital costs.
6. OEB blocks OPG’s push for more equity. OPG wanted to increase its equity, which would increase its earnings, from 45% of its capital structure to 49%. The main reason for a higher equity percentage, according to the utility, was that the Darlington Refurbishment Project (DRP) is a risky, multi-year capital spending project (see below) and, as such, it was only fair that the utility be allowed to earn more. The OEB rejected that argument, pointing out that OPG is afforded many levels of protection that limit the risk of the DRP, among other risks. The OEB highlighted that “the types of risks faced by other regulated entities, such as gas utilities, when embarking on major capital projects do not apply to OPG.” The OEB pointed out that the Ministry of Energy determined the “need” for the DRP and passed legislation ensuring the utility would recover all prudent costs associated with the project. While the project is risky, it’s unlikely that OPG will ever bear the true brunt of that risk.
7. Full amount of DRP will enter rate base in 2020. The DRP, the $12.8 billion refurbishment of four reactors, is being done in stages, with Unit 2 being the first reactor to undergo refurbishment. As such, OPG has applied to place the entire planning budget for the DRP and the costs associated with the Unit 2 refurb into rate base – so it can earn a return on those assets – in 2020, when Unit 2 is expected to be complete. This will add more than $5.1 billion to its rate base (and will subsequently result in its nuclear rate spiking higher). Many parties in the proceeding, including OEB’s own staff, suggested that some portion of contingency spending, totalling more than $694 million, be withheld from rate base until a review is conducted to determine whether that spending was prudent. The OEB dismissed those arguments.
8. Ontario kicks more costs to the future. While the province has moved to defer tens of billions of dollars in electricity costs as part of its Fair Hydro Plan, it also directed the OEB to implement “rate smoothing” of OPG’s nuclear rate. Over the next five years, OPG will defer more than $1 billion in costs – with future ratepayers left to pick up the tab. The cost of that deferral over the next five years will be $116 million in interest costs. The interest costs of the $1 billion in cost deferral over the next five years may rise to $470 million by the time the money is fully paid back, which won’t begin until the DRP is officially complete in 2026. Cost overruns at the DRP will result in even more cost deferral.
9. Pickering gets the green light for extended operations money. While nearly all decisions relating to new power generation in Ontario are now made by the Ministry of Energy – after it spent a decade wresting that power away from arm’s length energy agencies – the decision on whether the costs needed to keep the Pickering nuclear plant open until 2024 were prudent were to be made by the OEB and other regulatory bodies.
When asked about extending the life of the Pickering nuclear plant, the province said OPG had to go “through the OEB” for “regulatory approvals” before making a final decision. But in October the province explicitly included the extended operations of Pickering in its Long-Term Energy Plan – the official energy planning document that the OEB must follow. As such, the OEB has rubber-stamped $307 million in costs required to complete the necessary work to keep the plant open past the previous 2020 closing date, noting that the final decision rests with the Ministry of Energy. While the Ministry of Energy publicly pushed the Pickering decision to the OEB, the OEB has now kicked that decision back to the province.
According to an analysis done by one of the province’s energy agencies, keeping the Pickering plant open until 2024 may cost consumers as much as $500 million in unnecessary costs.
10. OPG won’t get to reset its nuclear production forecasts. OPG has never hit its own nuclear production forecasts, although it has moved closer to those targets in recent years. Due to the length of this application – five years, as opposed to a two- or three-year application the utility typically used in the past – and the number of uncertainties facing the utility, such as the DRP and extended Pickering operations, OPG proposed a “mid-term” review. Under this review, OPG would update its production forecast and any cost associated with that update would go into a deferral account and be collected or rebated to ratepayers at a later date. The OEB dismissed this request and told OPG it will have to live with its production forecasts for the entire five-year period.
Brady Yauch is an economist and Executive Director of the Consumer Policy Institute (CPI). You can reach Brady by email at: bradyyauch (at) consumerpolicyinstitute.org or by phone at (416) 964-9223 ext 236