This article covers the 1998 consultation that opened the third price control review, and the settlement that followed, for electricity distribution in England, Wales and Scotland. It begins where the second article in this series left off, with the networks a few years into private ownership, and it ends with the price control that took effect on 1 April 2000. The controls set at privatisation in 1990 are covered in the first article, and the 1995 review that came immediately before this one is the subject of the second article. Later reviews, from 2005 onward, are the subject of later articles.
Table 1: How the review unfolded, February 1998 to April 2000
Sources: OFFER (1998b); Ofgem (1999); Ajayi, Anaya and Pollitt (2021).
The accounts showed low-risk monopolies making high, steady profits, and the obvious question was how much of that should go back to customers. When the Office of Electricity Regulation (OFFER) opened the distribution price control review in February 1998, for the period from 2000, it started from that financial record.
The review covered fourteen public electricity suppliers, the twelve Regional Electricity Companies in England and Wales and two vertically integrated companies in Scotland. Each combined a regional distribution business with a supply business. Because electricity distribution is a natural monopoly, distribution charges were capped under a Retail Prices Index (RPI) minus X control, while the supply businesses were gradually being exposed to increased competition. As competition in supply grew, it mattered more and more where distribution ended and supply began.
Aggregate distribution operating profit was approximately 34% of turnover in the first year after privatisation and settled between 40% and 43% of turnover in every following year up to 1996/97.
That is a high margin for a low-risk regulated monopoly. Costs had fallen faster than the controls set at privatisation had assumed, which means that allowed revenues were set too high relative to the companies actual costs, and the difference stayed with the companies. Where that money had gone was the first thing the review wanted to know.
Figure 1: Distribution operating profit as a share of turnover, 1990/91 to 1996/97
Source: OFFER (1998b), p. 12. The 40% to 43% band applies to each year from 1991/92 to 1996/97.
Table 2: Distribution operating profit as a share of turnover
Source: OFFER (1998b), p. 12.
Eleven of the twelve England and Wales companies were taken over, most of them by international utilities, because bidders had worked out how much borrowing a secure monopoly cash flow could carry.
For the first five years, a government golden share protected the companies from takeover. As it lapsed, bidders recognised that the secure cash flows of a monopoly electricity distribution business could support far higher borrowing. Higher gearing was cheaper and more tax efficient than equity, and substituting equity for debt released cash for special dividends, share buybacks and the acquisitions themselves. Across 1995/96 and 1996/97 the companies paid out close to 4 billion pounds in dividends (including special dividends), and interest payments in 1996/97 were about three times their 1994/95 level.
The flotation of the National Grid Company gave a sense of the sums involved. The companies owned it jointly, and part of the proceeds funded a rebate of 50 pounds for every customer in England and Wales.
Table 3: What the takeover wave showed
Source: OFFER (1998b), pp. 3, 20 and 23.
The regulator had already tightened the control once, in the 1995 revision covered in the second article in this series. Faced with falling costs and the signals from the takeover market, the regulator had already cut distribution charges significantly, with real reductions of 11% to 17% in 1995/96 and a further 10% to 13% in 1996/97, then 3% a year in real terms to March 2000.
The cuts showed in the accounts. Distribution turnover and profit fell in the final two years of the period, and operating costs fell by about 18% between 1992/93 and 1996/97. By the eve of the review, average distribution charges were about 25% lower in real terms than in 1994/95, and domestic electricity prices about 15% lower.
So the 1998 review was not starting from scratch. It was reopening a settlement that had already been tightened once, and asking whether customers should now get a bigger share of the gains.
Figure 2: Real reductions in distribution charges set before the 1998 review, 1995/96 to 1999/2000
Source: OFFER (1998b), p. 7.
Table 4: Real reductions in distribution charges set before the 1998 review
Source: OFFER (1998b), p. 7.
Setting a price control comes down to a single estimate: the revenue an efficient company needs to operate the network, finance its investment and pay a fair return on the capital already invested in it.
The form of the control was settled first. The RPI minus X form was kept, because tying prices directly to actual profit weakens the incentive to be efficient and is hard to define and enforce. The Government had proposed adding an error correction mechanism, but the regulator decided that it was not an appropriate way forward. The control would run for a period in the usual four to six year range.
On capital expenditure, the companies had forecast about 7.7 billion pounds for the 1995 to 2000 period, and the control had funded roughly 90% of it. The principle carried into the new review was that customers should pay only for efficient investment that was actually needed, neither brought forward too early nor deferred too late.
Operating costs were hard to judge because the company always understands its own costs better than the regulator, and the companies’ forecasts were inconsistent. Their own projections ranged from a 6% reduction to a 45% increase, averaging areal rise of about 17%.
The regulator’s previous analysis had assumed real reductions of around 4% over 4years, while the companies’ operating costs had in fact fallen an average of 18%. That gap between forecast and outturn is the hardest thing about regulating by incentive. Rather than take the forecasts on trust, the review benchmarked the companies against each other and against best practice.
Figure 3: Operating costs: forecast against delivery
Source: OFFER, July 1998 consultation, p.34
Table 5: Operating costs: forecast against delivery
Source: OFFER, July 1998 consultation, p.34
The cost of capital takes as much judgement as arithmetic, and in a business this capital-intensive a small change in the figure moves allowed revenue a long way. The previous control had used a real pre-tax cost of capital of 7%, and the 2000 review asked whether that value was still appropriate.
The cost of capital calculation was built up in three steps. The cost of debt was calculated as the risk-free rate plus a premium for the company’s own borrowing risk. The cost of equity used the capital asset pricing model (CAPM) and was calculated as the risk-free rate plus the company’s beta multiplied by the equity risk premium. The two were then weighted according to the assumed company gearing levels. For the pre-tax calculation, the equity return was uplifted to allow for corporation tax.
The reference figures the review carried forward, drawn from precedent decisions on the National Grid Company and on Northern Ireland Electricity, were as follows.
Table 6: The cost of capital build-up carried into the 1998 review
Source: OFFER (1998b), Table 18, p. 40
The consultation then set out why 7% might no longer hold. The risk-free rate, taken from index-linked gilts, had probably fallen below the range used a year earlier. Dividend yields had continued their long decline, pointing to a lower equity risk premium. At the same time, there was evidence that the betas of some companies, particularly the Scottish ones, had risen. The open question was whether the balance of that evidence justified a figure below 7%.
The cost of capital sets the rate of return, but what a company actually earns is that rate applied to the regulatory asset base. Change the base and allowed revenue moves just as it would if the rate changed.
The asset base started from each company’s flotation value plus an uprate, and that uprate had already fallen once, as we covered in the previous article. The August 1994 proposals used a 50% uprate on flotation value. After the takeover bids and a 1995 competition inquiry, the regulator cut the uprate to 15%. The 1998 review asked whether even the 15% uplift should be maintained.
Figure 4: The uprate on flotation value used to set the asset base, 1994 to 1998
Source: OFFER (1998b), p. 43. The third bar is the open question the 1998 review put for consultation, not a decided figure.
Table 7: The uprate on flotation value used to set the asset base
Source: OFFER (1998b), p. 43.
The review also prepared the companies for competition in supply, linked allowed spending to the quality of service, and considered prepayment customers.
Because the supply business sat close to the monopoly wires, there was risk of cross-subsidy and price discrimination as supply opened to competition. The Government proposed splitting the single licence into separate distribution and supply licences, opening the way for the activities to sit in separate companies or ownership. Metering and meter reading were to open to competition from April 2000, while administration of the metering register would remain a monopoly. Competition in supply was already advanced for larger users, and the household market was due to open between September 1998 and the middle of 1999.
The review's answer was to link allowed spending to the standard of service customers should get, and to ask how much more they would pay for fewer interruptions. That question led to the 2001 information and incentive scheme project, which began to link a company’s revenue to interruption frequency and duration, and customer satisfaction.
The review also dealt with prepayment meters and energy efficiency. The position of prepayment meter customers, many of whom were among the poorest households and paid additional surcharges, was considered. Alongside a wider social action plan, the review examined whether those charges could be reduced or removed. On energy efficiency, the previous control had already reduced the units-distributed component of the revenue driver to 50%, with the remaining 50% linked to customer numbers, and had strengthened incentives relating to distribution losses.
The settlement cut the regional companies’ distribution revenue by an average of approximately 23% in the first year, roughly 503 million pounds at 1995 prices, and required reductions of 3% per year for the rest of the control period. It also set up the Information and Incentives Project, which went on to link revenue to service quality.
On the prepayment surcharges, the regulator decided to leave them out of the price control given the expected development of competition in the provision of metering services.
This 1998 paper opened a process that ran through draft proposals in 1999 to final proposals in December 1999, by which point OFFER had merged with the gas regulator to form the current Ofgem. The numbers came later, but the reasoning is clearest in the 1998 paper. It laid out the evidence, asked the questions, and said plainly that the two inputs that mattered most, the return on capital and the value of the asset base, could not be settled by arithmetic alone. That has been true of every price control since.
Table 8: The 2000 distribution price control settlement at a glance
Sources: Ofgem (1999); Ajayi, Anaya and Pollitt (2021); Ofgem (2002).
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