12 interviews of Christmas: Iwan Hughes, VPI Immingham

Happy Christmas to all our readers. To celebrate the start of 2020 we present 12 interviews previously only available to our subscribers.

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In the March 2019 issue of New Power Report Janet Wood discussed the uncertainties of operating in the UK power market with Iwan Hughes, head of policy and regulation strategy at VPI Immingham. Changing gas and power charges could shift cost fundamentals, while capacity and carbon markets face upheavals


Iwan Huges_JMP_2207 The Immingham CHP is a strategic asset for the UK, says Iwan Hughes, providing much of the energy (in the form of steam) on a site next to 25% of the UK’s oil refinery capacity. Its

ultimate owner is multinational commodities company Vitol. Nevertheless, for Hughes, head of policy and regulation strategy, the plant is a small cog in the UK’s power industry.

It doesn’t have the ‘birds-eye view’ of the UK that a large integrated power company would have, with visibility of transmission constraints and activity in different parts of the country. “We see these retrospectively,” he says, through balancing charges, so he has to rely on fundamentals as well as data published by National Grid, and by sources such as Remit. “We are despatching to the power markets and trying to optimise that asset as best we can with the information we have,” he says. The company wants to expand beyond its current portfolio, which includes two battery assets (10MW at Cleator in Cumbria and 40MW at Glassenbury in Kent, both with Enhanced Frequency Reserve
contracts). Combining that with the resource on board and experience building reciprocating engines, “we nicely cover the types of technologies that are being discussed at the moment and different forms of generation”, he says.

At the moment, however, further expansion looks testing. Hughes says that looking at his investment models all he sees is uncertainty.

The Capacity Market suspension has created one of those areas. “You need to know certain things are bankable and that is what the capacity market was,” he explains, because it had visibility four years ahead and over a 15-year contract.

With a growing pool of renewables making operating hours less frequent and predictable for gas, “the capacity market is vital to help bring new flexible capacity forward”, Hughes says. “Without the Capacity Market you are left with a model that has uncertainty all the way through it. That is the challenge. The more uncertainty you have in your model, the higher the cost of capital.”

Immingham (VPI-I) was the proposer for a Balancing and Settlement Code (BSC) modification that would have seen Capacity Market levies collected from suppliers while the market is in abeyance, and held for distribution to CM parties at a later date if the market was reinstated. “It was one of the first questions that we asked on the desk. The money wasn’t going to be there, so going to collect it in the future … the risk for supplier shocks and large bills to end consumers was high,” explains Hughes. The proposal was rejected by Ofgem, which said it did not come within its powers to rule on it.

The BSC modification would in any case have been withdrawn if BEIS made its own arrangements, an approach it is considering via revised regulations. A consultation on that option closed in January. Hughes describes the BSC modification as an attempt to support the Department for Business, Energy and Industrial Strategy, “during what is a difficult moment for them”. He recalls the instant when the European Court decision was announced and says: “It was quite a stark moment … Something that you thought was very bankable disappeared immediately.” He says BEIS managed to get its arms around the issue reasonably quickly, with officials holding regular weekly calls and being proactive around the consultation.

Since our conversation the extent of uncertainty has increased, as the Commission has decided that it needs to undertake a full investigation into the Capacity Market, which could take 18 months or more.

There are concerns as to the effect on security of supply of the CM suspension and we meet soon after EDF Energy announces plans to close the Cottam coal-fired plant before the winter season. But Hughes says that was “probably largely expected by the market. I’m sure there will be others to come… The simple way of doing it is just looking at the merit order and who has a Capacity Market contract and who hasn’t.”

The fact is, however, that although the Capacity Market suspension is perhaps the most unexpected change, it is just part of what a colleague of Hughes describes as a “blizzard of regulatory change”. Hughes notes that some of those changes come from BEIS, some from Ofgem and some from elsewhere, like the change in electricity system operator procurement.

He says: “It is a responsibility for BEIS to get a real handle on all these components’ moving parts,” and work out what they all mean for existing power markets, including that for the demand-side. BEIS should have the overview of “what does it mean for company economics? What could exit the market when? What could enter the market when?”

Asking: “What does your business model look like, to try to make a decision?” on whether to invest, he checks off some of the big-ticket changes that have affected the model.  They include Ofgem’s Targeted Charging Review, and review of access and forward-looking charges.

There have already been changes to embedded benefits, and “you don’t know what is happening with DUOS [distribution use of system charges] – there is a move to capacity charges perhaps on the cards”. Generators will be treated according to whether they are making the demand/supply situation worse at a grid supply point. “So what is my potential new project doing? Do I think that I am benefiting an area or am I making it worse? The traditional business model for looking at a distributed asset has changed. And it has changed since some Capacity Market agreements were entered into in 2015/16.”

Other grid charges are also uncertain. For example, the cost of transmission charging and of the new Electricity System Operator, being spun out within National Grid.

Hughes notes that at this stage in developing the next price control “we are all very focused on what it could mean to us individually. Ofgem has said that the allowed returns [for transmission network owners] will probably be lower than in RIIO T1, but we don’t know the size of the pot, so you don’t know how that could be smeared across or what it really means.”



On the gas side, the current charging review “is extremely significant”.

After many months of work, changes that would bring the GB market into line with the European Tariff Code, including a shift to a more capacity-based charge, were thrown out by Ofgem, although new charges are required by European legislation to be agreed by 31 May. An new urgent modification has been raised, but the industry is faced with trying to find a workable solution within a few weeks, so it can be implemented from the new ‘gas year’ on 1 October. That includes time to develop solutions that will pass muster with Ofgem and time to consult with the industry – a statutory requirement that takes the process past the May deadline.

The business model for looking at a distributed asset has changed since the first CM agreements

Hughes argues that GB is required only to use its “best endeavours” to make the change and he wants secretary of state Greg Clark to step in to extend the timetable.

Gas users – both generating companies and industry – are facing a blank where their gas delivery costs should be, Hughes says, and for many that understanding is already overdue. “Most businesses will do calendar year budget forecasts and reporting, and at the moment I’m unable to look at what my gas costs are,” he says.

Because the change in the gas charging regime, whatever its final form, will include a shift towards capacity charging, there are some fundamental effects that are wider than just gas price. “Charges that were factored into your short-run marginal cost now become essentially your fixed costs. If you were a new asset you could factor that into your capacity market price,” Hughes explains.

“If you are an existing asset … you could see an increase in costs, further squeezing your economics.” Now, he says, in despatch decisions, “long run marginal cost is also something that you need to consider”.

Also to be factored in to those decisions are new markets for ancillary services run by National Grid as system operator. Hughes describes the separation between the new body and the transmission network owner as “obviously positive” and sees more market trials coming through, such as for black start. “It will be interesting to see how they [the ESO] challenge different parts of the market now that they are separate from the transmission owner.”

He credits the ESO with trying to do an audit and rationalisation of ancillary services as it introduces new products, some of which were handled under different industry mechanisms (some ancillary services were required from participants under the grid code, for example). But to help VPI-I navigate that he wants “more real-time information … we live in a world where a question is asked and we need answers extremely quickly. Although I do not expect National Grid to look like me I cannot be expected to look like National Grid,” he says.

“We don’t necessarily have as many touch points” as other companies – especially those working across the UK and with supply businesses as well – and the ESO should not assume all companies start at the same information level.

His worry is making sure that shorter-term procurement of system services does not obscure market signals. “When the system operator takes an action by virtue of the fact that it is intervening within the market … it should always consider what the subsequent impact on the market could be,” he says.



We have not mentioned Brexit up to now in our discussion, but for thermal generation it introduces another level of uncertainty. For the first quarter of the year “we don’t know what the cost of carbon is”, says Hughes.

It depends whether the UK makes a deal with the EU and remains in the EU Emissions Trading Scheme (EU ETS). If that happens, most thermal generators apart from biomass will require allowances for the first quarter of the year, as well as paying the UK’s Carbon Price Floor.

The government has said that in the event there is no deal a £16/t tax will be introduced.

It is not clear what will happen if Article 50 were extended. But Hughes also says there is little information about the £16 tax itself. “Although large parts of the market think they know how it’s been calculated, the calculation is not public, and the forward methodology is not public, so we don’t know quite how long it would remain or how often it could be reviewed.” Companies trading power, “will be trying to optimise their assets out along the curve and so it’s important that the market has a reason- able degree of certainty around what the carbon price may be – whether this is a tax or other mechanism. If a tax with good visibility continued to recognise existing reliefs, it’s not something we’ve dismissed as an option”.

Longer term, will the UK’s carbon floor and tax remain stable? Finally, the relationship between national carbon markets, “is a significant cost of generation and the difference between carbon in one market versus another will help determine what the direction of flow is between markets.”



We are expecting an energy White Paper later this year and it is no surprise that when I ask Hughes what he wants from it he returns to his earlier concern about BEIS having a view of all the industry’s moving parts.

The department should be “ensuring that there is no policy and regulatory divergences and everyone is trying to achieve the same objectives and it is being done in a man-aged way … because the future is so uncertain the potential cost of getting it wrong could be significant”, he says.

Charges that were factored into your short-run marginal cost now become essentially your fixed costs

We are all agreed we are heading for a different system, he says. It shouldn’t be about transmission versus distribution. “We are certainly moving toward the smaller more flexible decentralised system and it’s important to know that. But it will also be a balanced sensible mix of lots of different types of capacity operating in different ways as consumer behaviour evolves over time.

“I’ve heard Claire Perry say on a number of occasions the energy market seems to be getting on with the job, and we are able to step back a little bit and watch it evolve and just correct policy where necessary.”

We know what the ambition is, he says, saying that the amount of wind brought onto the system and the investment in offshore wind has been “incredible”. VPI has invested to improve the plant’s flexibility and “that won’t just be unique to us”.

He would describe Immingham as being a strategically important asset, because of its role in providing industrial heat as well as power. And as well as investigating new power projects (see below) Hughes talks about Immingham as being as part of an ‘energy park’. “There’s a lot more that we can do there,” he says. That may include developing services for other businesses within the Humber area, or attracting investment from data centres. “All these types of opportunities exist and it’s something that we will actively explore.”

His final ask for the White Paper and for regulators is better information on changes. “We are trying to take a view on the future … if we are going to flag that changes are going to happen, and if the answer then isn’t apparent until a month before it comes into effect that’s not really flagging. Nobody has been able to prepare for the outcome.”



As an organisation “we are quite entrepreneurial,” says Hughes, and the company wants to grow by investing in new plant, in addition to its ‘energy park’ plans.

Next door to Immingham CHP the company is developing a 299 MW OCGT, VPI B. But the VPI group also has “a number of different brands that you would see coming through”. That includes VPI distributed generation, and VLC energy, the joint venture with Low Carbon through which the company owns the Cleator and Glassenbury storage projects. Prior to the last auction, when battery derating was revised, “we had many other battery projects in the pipeline. At the current time I can’t see us doing any more batteries in the UK”, says Hughes.

We don’t know what the cost of carbon is

Separately, the company has VLC R, also a joint venture with Low Carbon, which is looking at renewables. But it too has no active project at the moment.

Hughes declines to specify his ideal portfolio, but says: “Everyone is building up expertise and understanding around what intermittency looks like and how that plays into what assets you might want to be involved in.

“Around gas reciprocating engines it is worth noting … we have pre-qualified a 50MW gas recip engine connected to the low voltage side of one of Immingham’s transformers … We have 50MW of assigned TEC at Immingham within the bilateral connection agreement, so VPI Energy Park is utilising the assets that we own and trying to look at how the system will evolve in the next 10-20 years. “We are considering more transmission connected innovation, and believe that 50MW recip remains a strong project which would be very visible for the system.”


New Power Report subscription includes:

  • Weekly email Update
  • Monthly New Power Report – analysis and insight
  • Access to our online Database  - search and sort data on 2500 UK power assets 

For more details and to join our next free trial, send your name, job title, company and email address to Daniel Coyne: [email protected]   

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