Increasing market volatility in 2018 is compounded by rising policy costs and regulatory change. That presents greater risk but also significant opportunity for businesses that grasp it, say consultants and suppliers. Brendan Coyne reports
Average wholesale power prices are predicted to decline steadily for the next five years, according to ratings agency Moody’s.
In a report published late last year, the firm said it expects prices will fall from around £45/MWh today to £40/MWh in 2022.
Declining gas prices, low cost imports and stable carbon prices – the latter confirmed by the Autumn Budget – were the key drivers for its outlook.
However, traders interviewed by The Energyst said the outlook for both gas and electricity commodity prices may be more volatile than some suggest.
Meanwhile commodity prices now make up less than half of the power bill. For many industrial and commercial firms, non-commodity elements are set to increase to approximately two thirds of the bill by 2020.
So what should businesses do to insulate themselves from risk without paying through the nose while taking opportunities as they emerge?
Volatility: enemy and friend
“The key risk is volatility – and the key opportunity is volatility,” says Dave Cockshott, who spent two decades at Npower and Inenco before joining Smartest Energy in 2017 as chief commercial officer.
“I think many people have become complacent about the wholesale markets, which have generally moved sideways for some time.”
That may be a product of warnings of incoming volatility that “perhaps have not led to differentials being as high as I had expected. But that doesn’t mean volatility is not coming,” he says.
Cockshott nodded to recent disruptions at some of Europe’s key gas infrastructure – an explosion at the Baumgarten import hub, which saw significant spikes in same day and month ahead gas prices, which were already rising due to a fracture at the Forties pipeline, plus technical failures at the BBL pipeline and Norway’s Troll field.
He said those outages and their impact on market prices illustrate that “event risk can still cause shockwaves of volatility”.
Because the UK’s largest gas storage facility, Rough, is closing, those shockwaves will likely be greater than they have been in the past, he suggested, particularly if the weather is less benign that last winter.
“When Rough was taken out of action, the market took it in its stride and didn’t overreact. But there is a latent risk. Rough used to provide a cushion so we could draw down when needed. That cushion is no longer there, and markets will factor that into prices,” says Cockshott.
“I don’t think we should be overly worried, it’s just that everything comes at a price.”
For both gas and electricity, Cockshott said businesses should revisit risk strategies and stress-test them to react appropriately to foreseeable eventualities, “even if that reaction is to do nothing, which people forget is a decision in itself”.
Inenco’s Matt Osborne agrees lack of gas storage and the relatively bare forward schedule for UK LNG deliveries this winter creates risk. The firm advises clients to look closely at hedging strategies to protect themselves as there is “more upside risk than downside potential” heading into 2018.
Osborne says Brexit’s impact on Sterling and uncertainty over the length of French nuclear outages also creates power price risk. “As a range for 2018, we predict power prices could creep up between 5-20%,” he says.
“If everything goes to plan, then prices will probably be relatively benign. But at the moment, there is some upside risk in the market … It is perhaps not as benign [in the mid-term] as the Moody’s report makes out,” says Osborne.
Amber Energy CEO Nick Proctor agrees 5-20% upside risk for 2018 is a “fair comment”. But he underlines that only relates to the junior part of the bill. Non-commodity elements now make up the lion’s share. He thinks too many businesses are complacent in that respect.
“It is negligent just to have a trading policy and not an energy policy,” he says. With non-commodity aspects set to make up 65% of I&C bills within the next couple of years, Proctor expresses surprise that many firms remain singularly focused on commodity prices.
“In no other area of their business would they sign a contract based on 35% of its value,” he suggests.
Proctor says while Amber’s clients outsource that management strategies to its consultants, “when we pitch for new business, perhaps 50% are unable to competently talk about non-commodity costs”.
“Energy policies must include trading, procurement and risk, as well as flexibility, energy reduction and behaviour change in the building,” he says. “Businesses have to catch up.”
Non-commodity changes – network costs
Three network charging changes that will affect business bills and cost avoidance strategies come into effect from 1 April 2018.
DCP161 and DCP228 affect distribution network charges, which make up 10-15% of the average power bill.
DCP161 affects network capacity. Businesses have a set capacity, agreed with their distribution network operator, around the maximum demand they can import. Today, if they breach that capacity, they just pay the standard rate for any excess. But from April, breaching the agreed capacity limit incurs a penalty charge up to three times the standard rate.
DCP228 affects time of use tariffs – red, amber and green, or RAG, rates. To date, red rates have been many times higher than green rates, leading companies to adopt red band avoidance strategies. But from April, the RAG rates are being flattened, so that the difference between red and green rates is much less. While some companies may see smaller bills as a result, others face higher charges as avoidance measures become nullified.
Meanwhile, the P350 Balancing and Settlement Code (BSC) modification changes the way businesses are charged for power transmission losses. According to consultancy Inprova Energy, that could increase electricity bills for London business consumers by around 1.5%. Business energy consumers in the North and Scotland, however, are likely to pay less.
Jon Ferris, now at blockchain energy firm Electron, but who spent more than a decade with TPI Utilitywise, says DCP228 and DCP161 will affect network charge management strategies.
“There has been a big push over the last few years for half-hourly metered businesses to reduce agreed capacity with networks [because there was no penalty rate],” he says. “Now the penalty will be more punitive, so it is much more important to understand peak demand.”
Meanwhile, flattening of RAG rates under DCP228 could make red band avoidance less viable.
“If a business has already invested time and effort adjusting equipment and processes to avoid peak charges, they will probably stick to the same approach. Because a lot of the cost [of avoidance] is around operational processes,” says Ferris.
“Having changed them, you don’t want to incur further cost by changing back again. However, if you have not already adopted red band avoidance strategies, it becomes questionable whether the operational cost of doing so is sufficient, given the flattening of the charges.”
While changes to RAG rates may benefit some smaller firms, “they will really hurt companies that use a lot of power at off peak times, such as cold stores, data centres, those operating night shifts,” says Inenco’s David Oliver. “They might see £8-9/MWh increases for using power at night.”
Oliver suggests changes to network capacity charges also create a dilemma for companies planning for the medium term.
“If you think you might need EV charging in the future, you may wish to hold on to your capacity, because it might be very expensive to get back,” he suggests. If not, “you probably want to have a second look at it.”
Counter volatility with flexibility
According to Noveus Energy MD Bobby Collinson, the key energy risk in coming years “is definitely in balancing. Why? Because changes to things like embedded benefits will discourage peaking plant from coming forward – and peakers are one way of managing balancing risk,” he says.
“If you can’t do that with peakers, more and more renewables coming online means balancing becomes pretty expensive.”
National Grid has to keep the power system balanced. When supply and demand margins become tight, it pays generators – and aggregators – to pump power into the Balancing Mechanism, occasionally paying very high prices. These prices have to be higher than the generators would receive on the wholesale power market. And, if the system is tight, wholesale prices will also be high.
In the past, supply margins have been tightest over winter, which, as well as incentivising people to build new power stations, was a key rationale behind Capacity Mechanism. The Capacity Mechanism pays power generators (and demand-side response providers) to provide headroom on the power system over winter, with the costs added to bills (see box-out at the end of this article).
But last year imbalance prices topped £1,500/MWh in May, due to plant outages coinciding with low renewable generation. Prices also spiked in November.
Collinson thinks these “shoulder months” will continue to see volatility, which will impact energy strategies. But he agrees with Smartest Energy’s Dave Cockshott that volatility is also an opportunity for those firms that can harness flexibility, or demand-side response.
Flexibility risk management
That opportunity will increase from November 2018, according to Jeff Whittingham, managing director of Ørsted Energy Sales UK (Ørsted is the new name for Dong Energy).
Speaking at the Emex conference last November, Whittingham explained that changes to the rules that govern imbalance pricing will see the price cap double to £6,000/MWh. Prices will also be set on the last megawatt hour as opposed to the last 50MWh, which is likely to make it a “spikier” market.
That means higher rewards for companies that can sell their flexibility into the balancing market, and potentially the wholesale market as well, where prices may react in tandem.
As a result, Whittingham said companies must now consider “flexibility risk management” as part of their energy strategy.
Smartest Energy’s Dave Cockshott agrees. He suggests that most companies will find a degree of flexibility within their operations – if they look.
“Then it is about putting a price on that flexibility and taking the necessary steps to be able to react for an hour or so here and there when the price signals are right,” he says.
“Getting into a position to monetise that flexibility is essential” for firms in 2018, Cockshott suggests.
“There needs to be a sea change in attitude towards flexibility, because it is a risk management strategy. You might have best risk management strategy ever written on the procurement side. But if that is all you have, then you are quite literally now only doing half the job.”
Avoiding maximum demand penalties
Measuring maximum demand is not straightforward and requires an understanding of both reactive and active power, says Inprova managing Michael Dent. He says consultancies with data management services can guide businesses through the process but outlines the following key steps:
1. Understand your existing capacity agreement: Look at your history to see whether you have frequently hit or exceeded your Agreed Supply Capacity (ASC). This will identify whether DCP161 presents a risk.
2. Limit your power usage: Reducing your electricity usage, particularly your peak demand, could be a very effective method of countering charges. This will also reduce your overall electricity costs.
3. Don’t set your ASC too high: It may be tempting to increase your ASC to avoid the risk of incurring penalties, but you will have to pay for any unused capacity, which could work out more expensive. Consider the future growth or possible contraction plans for your organisation and how this may impact on your capacity requirements.
4. Beware new meters: It is especially important for organisations migrating to half hourly metering to gain a firm understanding of their ASC and to ensure that it aligns properly
with their existing and predicted future energy demand.
5. Plan ahead: Capacity planning must form an essential element of your energy strategy. It should be reviewed regularly and carefully.
Counting the cost of policy
Policy costs, loaded onto electricity rather than gas, make up around a third of the overall power bill. Here’s what the main elements are set to cost:
Capacity Market: The amount charged depends on business consumption, November to February, 4-7pm. Businesses consuming large amounts of power in those periods will pay more than those that don’t. Moving demand out of the winter peak also helps half-hourly metered customers avoid Triad periods. Conversely, the more people that take avoidance measures, the more those that don’t will pay.
This winter, the CM will add £381m to UK business bills. Over the 278 applicable evening winter peak hours, that translates to an additional £33/MWh, says Inenco’s David Oliver, “depending on a businesses’ consumption profile”. Next winter, that rises to £955m, which he estimates translates to £90/MWh during the applicable peak periods.
RO/CfD/Fit: The Renewables Obligation is the biggest policy item on bills. While the RO has closed to new schemes, renewables generators were allowed ‘grace periods’ and more generators are coming on-stream. With exemptions given to energy intensive firms, plus retail price inflation, RO costs look set to increase 15-20% year on year in 2018 to around £22MWh.
Exemptions for energy intensive industries will also push up Contract for Difference and Feed-in Tariff costs. For now these remain a relatively minor part of the overall bill, and deployment caps limit their increases. However, they will rise significantly in coming years.
CCL: Climate Change Levy costs will increase slightly in April 2018, before jumping sharply in 2019 due to the scrapping of the CRC as the Treasury looks to protect tax revenues.
Views on 2018 energy risks and opportunities
Magnus Walker, director, trading and risk management, Inprova Energy: “The extreme volatility of energy markets shows no signs of changing as we go into 2018. Overall last year there was a 45% price swing in wholesale power prices and market swings looks set to continue as European and global commodity markets become ever more linked. It’s more important than ever to purchase energy wisely using market intelligence, and to ensure that procurement is underpinned by a ‘bullet-proof’ risk management strategy.”
Laura Cohen, chief executive, British Ceramic Confederation: “Improving UK energy security, particularly gas security and reducing price volatility remains a priority for our members. We and others have already called on the government to mount a fresh inquiry into gas security, with particular reference to the adequacy of UK storage, gas price security and the possibility of taking some form of regulatory action to mitigate the impact of increased energy price volatility.”
Laura Bazeley, risk manager, Mitie Energy: “We expect non-commodity charges for power to rise by around 15-20% next year for a typical large retail consumer, though the actual increase will vary significantly depending on distribution of sites and consumption profile.”
Matt Dracup, I&C energy services director, Engie: “There is a danger of focusing on individual aspects of energy, which can result in value being missed. It’s important to understand the inter-relationships of procurement, management and flexibility. Customers really need to look at procurement, energy efficiency, compliance, DSR, batteries etc together to identify the best areas for them to focus on.”
Jo Butlin, CEO, EnergyBridge: “Businesses taking a genuinely integrated energy strategy across storage, generation and consumption are the ones that will win.”
This article was originally published in The Energyst’s January print issue. The magazine covers all aspects of business energy and is free to those with some responsibility for energy within their organisation. If you would like to subscribe, click here.
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