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This article covers the review that reset Great Britain's electricity distribution price controls from 1 April 2010, known as DPCR5. It follows the fourth article in this series, on the 2004 review, and is followed by the sixth, on RIIO-ED1. It draws primarily on Ofgem's December 2009 final proposals and on one of the four accompanying technical documents, covering allowed revenues and financial issues, cross-checked against Ofgem's press notice of 7 December 2009.
Table 1: How the review unfolded, March 2008 to April 2010
DPCR5 set the maximum revenues that each of the fourteen regional distribution monopolies could collect from customers between 2010 and 2015, at a level intended to let an efficient business finance its activities, together with the incentives on reliability, customer service, losses and the connection of distributed generation. Structurally it inherited the DPCR4 architecture, with a building-block calculation of allowed revenue, benchmarked costs, a menu mechanism for expenditure forecasts and a separately calculated tax allowance.
Its timing set it apart. The review was conducted through the credit crunch and its aftermath, when the cost and availability of finance for capital-intensive utilities was uncertain, and alongside Ofgem’s RPI-X@20 project, a root-and-branch reassessment of the regulatory model itself. DPCR5 therefore had to keep a familiar framework steady while the model behind it was being reconsidered.
The crisis dominated the cost of capital debate. The companies, supported by analysis from NERA, argued for a higher cost of equity than at DPCR4, drawing on a dividend growth model and pointing to elevated debt issuance costs. Centrica, a large supplier paying the charges, submitted analysis from CEPA concluding that the DPCR5 cost of capital could be up to one percentage point lower than DPCR4, because falling risk-free rates had more than offset higher credit spreads and utility shares had been less volatile than the market through the crisis.
Ofgem commissioned its own advice from PricewaterhouseCoopers and monitored market conditions through the review. By final proposals its judgement was that liquidity and stability had returned to the debt markets, especially for low-risk borrowers such as electricity distribution companies, with credit spreads falling for A and BBB-rated issuers and yields on index-linked gilts declining. It also considered, and rejected after consultation, a re-opener trigger mechanism for the cost of debt: the companies were almost unanimously against it, and Ofgem concluded that they were best placed to manage their own financing costs. That decision left the debt allowance fixed for five years, a choice with consequences discussed at the end of this article.
From the market evidence, Ofgem estimated that the companies could finance themselves at a vanilla weighted average cost of capital of between 4.3% and 4.9%, equivalent to 3.7% to 4.3% post tax, and chose a spot of 4.7% vanilla, or 4.0% post tax. The vanilla measure, combining a pre-tax cost of debt with a post-tax cost of equity, is the figure used to calculate the cash return on the regulatory asset value in the financial model.
Table 2: The DPCR5 cost of capital decision
Figure 1: The DPCR5 cost of capital against DPCR4
Two judgements sat behind the spot decision. First, notional gearing rose from 57.5% to 65%. Actual gearing in the ownership groups suggested an even higher figure could be justified, but Ofgem valued stability between reviews and noted that a level at the low end of the plausible range gave companies further headroom. Second, and more significant methodologically, Ofgem calibrated the cost of capital using its new return on regulatory equity measure, modelling the plausible range of equity returns from the whole package under different performance scenarios. At the chosen spot, the best performers could earn strong equity returns while the least efficient should fail to earn the assumed cost of equity. The equity beta of a distribution company, Ofgem concluded, was clearly below one: these are lower-risk businesses than the average firm.
The final settlement allowed £7.2 billion of investment over the five years, up 40% on the previous period. Within that, £6.7 billion was network capital expenditure and £500 million was the new Low Carbon Networks Fund. Ofgem cut the companies’ bids by around 8% overall to secure value for money, but the two most efficient companies were allowed the full sums they had requested, a demonstration of the menu logic inherited from DPCR4: companies that submit realistic, efficient and well-justified plans were allowed them in full.
The expenditure incentive itself was rebuilt. At earlier reviews, operating and capital expenditure carried different incentive strengths, which rewarded companies for classifying costs favourably rather than for genuine efficiency. DPCR5 equalised the treatment: for every company, 85% of all efficient relevant expenditure was added to the regulatory asset value and recovered slowly, while the remaining 15% was recovered in the year it was incurred. Relevant expenditure excluded business support costs, non-operational capital expenditure, excluded services and legacy metering. Combined with the information quality incentive, the menu mechanism developed from DPCR4’s sliding scale, this took British regulation most of the way to the total expenditure approach that RIIO would formalise.
The regulatory asset value is the value attributed to the long-lived network assets that deliver services to customers over many years. Allowed revenues are set so that an efficient company earns a return on the asset value at least equal to its cost of capital, together with regulatory depreciation that returns the capital itself over the assumed asset lives. As earlier articles in this series traced, this asset base descends directly from the flotation values of 1990 and the uprate decisions of 1994 and 1995, rolled forward through every subsequent review by additions and depreciation.
For DPCR5, the opening regulatory asset value at 1 April 2010 was £16.1 billion in 2007-08 prices across the fourteen companies, based on actual costs to 31 March 2009 and company forecasts for the final year of DPCR4.
Figure 2: Opening regulatory asset value at 1 April 2010, by company, in 2007-08 prices
Rather than allow revenues to jump in the first year and then flatten, Ofgem smoothed each company’s allowed revenue path into a constant percentage increase in each year of the control, on the grounds that its duty to protect consumers gave significant weight to avoiding sudden charge rises. In present value terms the companies received the same money either way, and Ofgem checked that the profiling created no financeability problems against its three key credit ratios. The resulting smoothed increases varied by company, from around -4% a year in real terms to around 11% a year for the companies with the largest investment programmes relative to their revenues.
For households, the effect was modest: an average increase of about £4.30 a year on an electricity bill, in exchange for higher investment, tougher reliability and customer service targets, and the low carbon trials described below.
The biggest change was the Low Carbon Networks Fund, worth up to £500 million over the period. It funded large-scale trials of smart grid technology, new commercial arrangements and network solutions for a low carbon economy, with a competitive tier in which companies bid annually for the best projects and shared the learning across the sector. It was the first time a British price control had carved out substantial ring-fenced funding for innovation and it became the model for the network innovation competitions of the RIIO era.
A broader package sat around it, covering a requirement to deliver defined network outputs and workforce renewal for which allowances had been provided, separate funds for undergrounding in areas of outstanding natural beauty and for the worst served customers on the networks, continued incentives on losses, distributed generation and quality of service, pass-through of specified non-controllable costs, and adjustment mechanisms for uncertain items including tax, pensions and the costs of the Traffic Management Act. Pension costs were split, with deficit repair costs treated separately from ongoing costs, and sharing rules applied to differences between allowances and outturn. A tax trigger handled changes in tax liabilities, and the DPCR4 claw-back for excess gearing was carried forward.
DPCR5 closed the sequence of five-year RPI-X distribution reviews that began, as the second article in this series described, with the 1995 reset. Even as the final proposals were being written, the same Ofgem team was running RPI-X@20, a review of whether the regulatory model that had served since privatisation was still fit for a sector about to decarbonise. The conclusion, reached in October 2010, was the RIIO framework: eight-year controls, revenues tied explicitly to outputs, total expenditure allowances, stronger innovation funding and the possibility of fast-tracking well-justified business plans.
DPCR5’s own record fed that reform. Its equalised incentives and information quality incentive worked well enough to be generalised. Its fixed cost of debt allowance did not: interest rates fell well below the level assumed in December 2009, handing the companies a windfall that Ofgem later acknowledged when reviewing performance, and RIIO replaced the fixed allowance with an indexed one. Both points run directly into the next article in this series, on RIIO-ED1, the first electricity distribution price control of the new era.
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