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This article covers the review that set Great Britain’s electricity distribution price controls for 2015 to 2023, known as RIIO-ED1. It follows the fifth article in this series, on the 2009 review, and will be followed by an article on RIIO-ED2. It draws primarily on Ofgem’s final determinations overview of November 2014, the equity market return decision of February 2014 and the fast-track decision letter, with the retrospective assessment drawn from the National Audit Office’s 2020 report on electricity networks.
Table 1: How the review unfolded, October 2010 to April 2015
RIIO stands for Revenue = Incentives + Innovation + Outputs. Ofgem’s RPI-X@20 project settled on it in 2010, after asking whether the regulatory model in place since privatisation could carry the sector through decarbonisation. The core of RPI-X survived, with multi-year revenue caps, a regulatory asset base, a cost of capital and strong efficiency incentives, the machinery this series has traced from the 1995 review onwards. The packaging changed. Controls would run for eight years instead of five. Revenues would be tied explicitly to output commitments across safety, reliability, the environment, connections, customer service and social obligations. Operating and capital expenditure would be assessed together as total expenditure, completing the journey DPCR5 began with its equalised incentives. Companies producing well-justified business plans could be fast-tracked, settling their control early on the plan as submitted.
RIIO-ED1 was the first application of this model to electricity distribution, covering the same fourteen licensees as DPCR5, by then held in six ownership groups.
The fast-track offer was designed to change behaviour before a single number was set, since the prospect of early settlement and lighter scrutiny pushed every company to sharpen its plan. Ofgem judged that the possibility inspired all the companies to raise their game, but only Western Power Distribution’s four licensees cleared the hurdle, and their price control was concluded in February 2014 on the plans as submitted, subject to one change described below. Ofgem estimated the distribution element of bills for Western Power Distribution’s customers, nationally about 19% of an average annual electricity bill, would fall by 13.9% in 2015-16, around £13.50 in 2012-13 prices.
Fast-tracking was worth having. Ofgem later calculated the financial benefit to the company at around £250 million, since a fast-tracked plan is accepted rather than benchmarked down, and the company kept the original fixed ten-year cost of debt index design rather than the revised version applied to the others. Ofgem defended the asymmetry openly in the final determinations: the fast-track process had produced better initial business plans across the sector, a further £700 million of reductions between the first and revised slow-track plans, and better benchmarking data, benefits it judged greater than the advantage to the fast-tracked company.
The cost of equity decision arrived in two steps, and an appeal in a different jurisdiction forced the second. Ofgem’s central reference point for assessing the plans was 6.3%, against the 6.7% the companies had themselves proposed. In November 2013 the Competition Commission published its provisional determination for Northern Ireland Electricity, giving materially more weight to current market evidence on equity returns than British energy regulation had done. Ofgem consulted, and in February 2014 decided to give greater weight to current market conditions, cutting its central reference point for the cost of equity to 6.0%, a reduction of 0.3 percentage points from the figure used in the business plan assessment. Western Power Distribution accepted a 0.3 point reduction of its own, to 6.4%, as the condition of staying fast-tracked, which brought its opening weighted average cost of capital to 3.9%.
The debt side changed more fundamentally. DPCR5 had fixed the cost of debt allowance for five years, and falling interest rates turned that fixed allowance into a significant source of outperformance for the companies. Under RIIO-ED1 the allowance is calculated each year from a trailing average of iBoxx non-financial corporate bond yields of ten years and over, deflated by implied inflation, with the averaging window extending by one year each year from a ten-year starting point. This trombone design largely removed the sector’s exposure to interest rate uncertainty in either direction.
Figure 1: The allowed cost of equity from DPCR4 to RIIO-ED1, post-tax real at the notional gearing of each review
Expenditure was assessed on a total expenditure basis for the first time, using three benchmarking models: a top-down model with high-level cost drivers, a bottom-up model built from disaggregated activity drivers, and a fully disaggregated activity-level assessment, weighted 25%, 25% and 50% respectively. Companies were benchmarked against the upper quartile, and each company’s allowance was then set by interpolation, 75% on Ofgem’s view of efficient cost and 25% on the company’s own forecast, with the information quality incentive giving companies that forecast closer to Ofgem’s view a stronger efficiency incentive rate.
Three adjustments did most of the work on the slow-track plans. The comparative cost assessment identified over £700 million of scope for reduction. Ofgem’s view of the savings available from smart grid solutions, beyond the £476 million the companies had already included, removed a further £322 million. And an updated assessment of real price effects, the expected movement of network input costs relative to inflation, came in £728 million below the companies’ forecasts. The result was a final slow-track allowance of £17.5 billion in 2012-13 prices, 7% below the companies’ revised plans and 11% below their original submissions.
Figure 2: Slow-track total expenditure by company: submitted plans, Ofgem’s view of efficient costs and final allowances after interpolation, in 2012-13 prices
The output framework was RIIO’s defining feature, tying revenue to commitments the companies had to meet rather than to costs alone. The interruptions incentive scheme continued to reward and penalise performance on the number and duration of power cuts against company-specific targets. A broad measure of customer service combined a satisfaction survey, a complaints metric and an assessment of stakeholder engagement, and a time-to-connect incentive covered smaller connections. On the environment, losses moved from a troubled financial incentive to a licence requirement to keep losses as low as reasonably practicable, supported by published losses strategies, while companies reported their business carbon footprint. Innovation funding continued through the Network Innovation Allowance and an annual Network Innovation Competition, the successors to the Low Carbon Networks Fund described in the previous article.
The financial arrangements changed to match the longer horizon. Regulatory asset lives for new additions were extended from 20 to 45 years, phased over the eight-year period, so that customers pay for assets across something closer to their economic life, and capitalisation rates of between 64% and 80% determined how much of each company’s expenditure entered the asset base rather than being recovered in-year.
Table 2: The RIIO-ED1 financial package against DPCR5
The headline effect was a reduction. Allowed revenues fell by around 4.7% on average over RIIO-ED1 relative to the final year of DPCR5, an underlying reduction of about £12 in the typical annual household bill, while the ten slow-track companies were still able to spend £17.5 billion renewing, maintaining and operating the networks. Base revenues for the ten slow-track companies totalled £28.5 billion over the eight years in 2012-13 prices. Ofgem’s return on regulatory equity analysis, the tool introduced at DPCR5, indicated that outperforming companies could earn equity returns above 10% while underperformers could fall below the cost of debt, a deliberately wide range intended to make the incentives bite.
Operationally, it delivered. The National Audit Office’s January 2020 review of electricity networks found that consumers in Great Britain experienced fewer power cuts than in most other European Union countries and that the network companies had met almost all of their targets across safety, the environment, reliability, connections, customer service and support for vulnerable consumers. Ofgem’s own annual reports on the control tracked most companies earning rewards on reliability and customer service, with customers benefiting directly from the improved performance.
Financially, the verdict was harsher. The National Audit Office found the network companies on course for shareholder returns of around 9% in real terms against a United Kingdom company average of around 5% to 6%, with about 1.5 percentage points coming from incentive rewards against targets that were in some cases already being beaten before the control began, and about 1.2 percentage points from spending below allowances. It estimated that consumers could have paid at least £800 million less had Ofgem placed more weight on up-to-date evidence about network company risk, and it criticised the eight-year length for locking in the settlement too long. Ofgem’s response acknowledged that overall costs to consumers had turned out higher than necessary, noting that over £6 billion had been shared back with customers across the networks through the sharing mechanisms and voluntary contributions, and pointing to the tougher settlements then in preparation.
RIIO-ED1 repeated the oldest pattern in this series. A control calibrated on cautious assumptions about risk and cost was outperformed by companies that turned out to be safer and cheaper to run than assumed. The 1990 controls taught that lesson first, as the opening article described. RIIO-ED1 taught it again, and its successors answered. The RIIO-2 controls and RIIO-ED2 cut allowed equity returns substantially and returned to five-year periods. That review is the subject of the next article in this series.
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