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This article covers RIIO-ED2, the price control that took effect for Great Britain's fourteen electricity distribution network operators on 1 April 2023. It is the seventh article in this series and follows the sixth, on RIIO-ED1. It draws primarily on Ofgem's final determinations overview, the finance annex and the core methodology document of 30 November 2022, together with the company annexes, the June 2022 draft determinations and the Competition and Markets Authority's September 2023 appeal decision. Figures are in 2020/21 prices unless stated otherwise.
Table 1: How the review unfolded, August 2019 to February 2024
RIIO-ED2 was shaped by what its predecessor had come to stand for. As the previous article in this series set out, RIIO-ED1 delivered operationally but left companies on course for returns of around 9% in real terms against a United Kingdom company average of 5% to 6%, and the National Audit Office criticised the eight-year length for locking in a generous settlement. Ofgem had already answered for the transmission and gas distribution sectors in the RIIO-2 controls that began in 2021: five-year periods, materially lower equity returns, weaker totex incentives and a backstop on aggregate returns. RIIO-ED2 extended that answer to electricity distribution.
The process itself changed too. Fast-tracking was dropped. At RIIO-ED1, it had handed Western Power Distribution an early settlement, an allowed cost of equity of 6.4% against 6.0% for the ten companies settled late, an efficiency incentive rate of 70% against 53% to 58%, and a financial benefit Ofgem put at around £250 million. In its place came a business plan incentive that rewarded well justified, ambitious plans and penalised poorly evidenced costs, applied to all companies on a single timetable. An enhanced engagement structure surrounded the plans: each company faced an independent customer engagement group, a central RIIO-ED2 challenge group reported on all fourteen plans on 8 February 2022, and public open hearings in March 2022 let stakeholders question the companies directly, a first for a British network price control.
Ownership changed mid-review. Western Power Distribution, the fast-track star of RIIO-ED1, had been acquired by National Grid and was renamed National Grid Electricity Distribution on 21 September 2022, so the four Midlands, South West and South Wales licensees appear under that name in the final determinations. The energy crisis that followed the Russian invasion of Ukraine formed the backdrop to the decision: Ofgem framed the settlement as accelerating the move away from imported gas at no extra cost to consumers, with the average consumer paying about £91 a year for electricity distribution within their bills.
The companies submitted plans totalling £25.2 billion of net total expenditure. Ofgem's June 2022 draft determinations allowed £20.9 billion, an average cut of about 17%. The final determinations settled at £22.2 billion, 12% below the submitted plans: additional evidence in consultation responses, revisions to the benchmarking models and a softening of the ongoing efficiency target from 1.2% to 1.0% a year restored £1.3 billion between draft and final. That £22.2 billion is measured before non-price control allocations and post-modelling adjustments. After those, and including the £0.4 billion allowed for the Access and Forward-Looking Charges decision, ex ante allowances settled at £21.4 billion, which Ofgem presented as a 17% increase in annual average spending against RIIO-ED1 outturn and forecast levels.
Figure 1: Submitted, draft and final total expenditure by licensee, £m in 2020/21 prices
The dispersion across companies shows how the assessment worked. The largest percentage cuts fell on National Grid Electricity Distribution's South West licensee, at 17.6% below its plan, and on Scottish and Southern Electricity Networks' southern licensee at 15.5%, while UK Power Networks' three licensees, judged among the most efficient, lost only 5% to 8%. Benchmarking used total expenditure models alongside a disaggregated activity-level model, with the efficiency frontier set at the 75th percentile in the first year, tightening along a glide path to the 85th percentile for the final two years of the control. Alongside that catch-up challenge, Ofgem applied an ongoing efficiency assumption of 1.0% a year, down from 1.2% at draft determinations, which it expects even frontier companies to deliver.
Table 2: Submitted and allowed total expenditure by licensee (£m, 2020/21 prices)
RIIO-ED2 was the first distribution control set in CPIH-real terms, ending three decades of Retail Prices Index linkage in the sector, and the methodology followed the RIIO-2 transmission and gas distribution controls as tested in the 2021 appeals to the Competition and Markets Authority. Ofgem set the allowed return on equity at 5.23% at 60% notional gearing, built from a risk-free rate of 1.23%, a total market return of 6.50% and a notional equity beta of 0.759. One legacy of the appeals shaped the number: the 25 basis point deduction for expected outperformance that Ofgem had applied in the earlier RIIO-2 controls, and which the appeal panel quashed, was dropped.
The equity decision moved a long way within the review. The June 2022 draft proposed 4.75%; by November the yields on index-linked gilts had risen sharply, lifting the risk-free rate from minus 0.74% to plus 1.23% and the final allowance to 5.23%. The debt allowance moved the same way, from around 2.3% to 3.01% for the three licensees classed as frequent issuers and 3.07% for the rest, based on a 17-year trailing average of the iBoxx GBP Utilities 10yr+ index with a 55 basis point calibration adjustment and 25 basis points for additional borrowing costs, deflated to CPIH-real terms. The 6 basis point gap between the two figures is an infrequent issuer premium, paid to every licensee expected to issue less than £250 million of new debt a year. Both allowances are indexed, so they move with markets during the period rather than being fixed for five years, completing a journey that began with the debt index at RIIO-ED1.
Figure 2: The RIIO-ED2 cost of capital at draft and final determinations, CPIH real
Table 3: The RIIO-ED2 baseline allowed return on capital (five-year average, CPIH real)
On a like-for-like basis the equity allowance fell hard. Ofgem's RIIO-ED1 allowance of 6.0% was set in Retail Prices Index terms. Restated on the 0.7 percentage point RPI to CPIH inflation wedge Ofgem used at these determinations, it is about 6.7% in CPIH terms, so 5.23% is a cut of about one and a half percentage points on a comparable basis. The largest step at any earlier review in this series was the 0.8 percentage point fall from 7.5% at DPCR4 to 6.7% at DPCR5. Notional gearing came down from 65% to 60%, partly reversing the increases of 2004 and 2009, and the 45-year asset life for new additions, introduced at RIIO-ED1, was retained. Ofgem judged each notional company financeable, with one, two or three notches of headroom above minimum investment grade.
The hardest design problem at RIIO-ED2 was that nobody knew how quickly electrification would come. Fixing five years of load-related investment upfront risked either paying for reinforcement that demand never called for, or starving networks that faced a surge of electric vehicles and heat pumps. Ofgem's answer was to fund only work that was certain in need and cost, and to route the rest through thirty-seven common uncertainty mechanisms plus seven bespoke ones: volume drivers that scale allowances automatically with delivered work, sixteen re-opener windows for costs that become clear in period, pass-throughs, indexation and use-it-or-lose-it allowances.
Most of that machinery deals with load-related investment. Volume drivers cover low voltage service connections and secondary reinforcement, a load-related re-opener handles larger schemes, and an indirect scaler adds 10.8% to each unit of load-related allowance to fund the associated overheads. The materiality threshold for re-opener applications was halved from the draft position, to 0.5% of annual average base revenue, after the companies argued that a five-year control with lower upfront allowances needed easier access to in-period adjustment. Re-openers for Storm Arwen recommendations, wayleaves and diversions, high value projects above £25 million, net zero policy change, cyber resilience and digitalisation completed the set. Against the fixed five-year settlements of the RPI-X era covered earlier in this series, RIIO-ED2 is better described as a framework for continuous determination than as a single determination.
The outputs framework carried over the RIIO structure of licence obligations, price control deliverables and output delivery incentives, with seven common financial incentives. The interruptions incentive remained the most powerful, worth up to plus 1.5% or minus 2.5% of the return on regulatory equity, alongside customer satisfaction at plus or minus 0.4%, and new incentives for distribution system operation, consumer vulnerability and major connections. The combined common package spans plus 2.65% to minus 4% of the return on regulatory equity. A new set of obligations and incentives for the distribution system operator role, with executive accountability for neutral decisions between running the network and operating the system, marked the arrival of flexibility markets in the licence itself.
Two mechanisms pulled the other way. Totex sharing factors were set between 49.3% and 50.0%, down from 53% to 58% for the ten companies settled late at RIIO-ED1 and 70% for fast-tracked Western Power Distribution, so companies keep less of any underspend and bear less of any overspend. And a return adjustment mechanism, new to distribution, claws back 50% of returns more than 300 basis points above or below the baseline allowed return and 90% beyond 400 basis points, in both directions. Set alongside the business plan incentive and the uncertainty machinery, these show what the design was for. After two decades in which companies systematically beat their settlements, the scope for outperformance was engineered down.
Ofgem decided the implementing licence modifications on 3 February 2023 and the control began on 1 April 2023. One group appealed. Northern Powergrid's two licensees challenged the settlement at the Competition and Markets Authority in March 2023 on two grounds: that Ofgem had misallocated allowances between cost categories, leaving the load-related element underfunded, and that its Yorkshire licensee had been wrongly denied a business plan incentive reward. On 21 September 2023 the authority upheld the first ground and dismissed the second, remitting the allocation question to Ofgem for redetermination, which Ofgem implemented through revised licence conditions in February 2024.
That one group appealed, and on one narrow issue, is worth noting. The RIIO-2 transmission and gas distribution determinations of 2020 had drawn eight appeals covering nine companies, including a direct challenge to the cost of equity that the authority rejected outright. By the time RIIO-ED2 was decided, the equity methodology had survived that test, and no distribution company chose to relitigate it. The contested ground had moved from how much investors should earn to how allowances should flex with an uncertain energy transition, which is where the preparations for RIIO-ED3 now sit: Ofgem confirmed the framework for the next control in April 2025 and its sector specific methodology in May 2026, ahead of a start on 1 April 2028.
Against the thirty years this series covers, RIIO-ED2 does two things. The first is a correction, and it addresses the oldest pattern in these articles, from the 1995 reopening through the National Audit Office's findings on RIIO-ED1: controls calibrated cautiously on risk and cost, outperformed by companies safer and cheaper to run than assumed. RIIO-ED2's response was structural. An equity allowance about one and a half percentage points lower on a comparable basis, weaker sharing factors, a clawback on aggregate returns, and a five-year horizon restored.
The second is a change in what a price control is for. The reviews of 1990 to 2009 asked how little an existing network could cost; RIIO-ED2 asks how a network should be rebuilt for electrified heat and transport without paying for capacity before it is needed. Much of the design effort went into mechanisms for changing the answer mid-period. Whether that adaptive model can fund the largest re-engineering of the distribution networks since their construction, while holding returns to utility levels, is the question RIIO-ED3 inherits. That is where this series picks up next.
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