# TUS Group > The Utility Solutions Group (TUS) is a UK commercial energy consultancy. We negotiate energy and water contracts, run flex purchasing portfolios (150+ GWh under management; +20% vs supplier projections last 12 months), deliver voltage optimisation, solar PV, battery and CHP projects, and report carbon for UK businesses — power, gas and water under one roof, with a named account director and the free Yolk portal included. ## Key facts - 150+ GWh under flex management - 30+ supplier panel for competitive procurement - Beat supplier projections by 20% over the last 12 months on the flex portfolio - UK-wide; HQ phone +44 330 117 0120; customerqueries@tus.group - Yolk portal: free for UK business, 27% average switching saving, no setup fees ## Services and products - [Procurement](https://tus.group/services/procurement): Open competitive procurement across a 30+ UK supplier panel. - [Flex Portfolio](https://tus.group/flex): Actively-traded flex contracts. 150+ GWh under management; beat supplier projections by 20% in the last 12 months. - [Multipurchase](https://tus.group/multipurchase): Flex discipline inside a fixed-term supplier wrapper for 1–5 GWh portfolios. - [Account management](https://tus.group/services/account-management): Named account director, monthly invoice validation, quarterly written review. - [Long-term planning](https://tus.group/services/long-term-planning): 3–5 year energy and net-zero roadmap modelled in pounds and tonnes. - [Voltage Optimisation](https://tus.group/voltage-optimisation): 5–15% off your electricity bill with a 2–3 year payback. - [Solar PV](https://tus.group/solar): Commercial solar PV designed around the half-hourly load, with the supply contract restructured to remove take-or-pay penalties. - [Battery storage](https://tus.group/battery-storage): Commercial battery storage stacking solar time-shift, peak-tariff avoidance, flex-market revenue and resilience. - [CHP](https://tus.group/chp): Combined Heat and Power for heat-led UK sites — modelled half-hourly before recommending. - [EV charging](https://tus.group/ev-charging): Workplace, fleet and customer-facing EV charging with DNO connection work and tariff restructuring. - [Water](https://tus.group/water): Business water retailer switching, billing audits and leak detection in the deregulated UK market. - [Carbon reporting](https://tus.group/carbon-reporting): SECR, GHG Protocol Scope 1/2/3 and ESG framework alignment (CDP, EcoVadis). - [Yolk portal](https://tus.group/yolk): Free AI energy management portal — benchmarks, alerts, multi-site dashboards and supplier switching across our 30+ panel. ## Sectors - [Manufacturing](https://tus.group/sectors/manufacturing) - [Education](https://tus.group/sectors/education) - [Retail & hospitality](https://tus.group/sectors/retail-hospitality) - [Charities](https://tus.group/sectors/charities) - [Sports & leisure](https://tus.group/sectors/sports-leisure) - [Healthcare](https://tus.group/sectors/healthcare) - [Faith & community](https://tus.group/sectors/faith) - [Corporate multi-site](https://tus.group/sectors/multisite) ## Recent UK energy market reports - [UK Energy Market Report — 10 Sep 2026](https://tus.group/market-insights/2026-09-10-uk-energy-market-report): Regulatory funding streams and heat‑pump rollout signal growing demand for low‑carbon electricity, while the latest CfD clean‑industry bonus and heat‑network scheme offer near‑term financing options. Global oil prices have breached $100/barrel and European power markets are seeing negative prices, adding pressure on wholesale rates. Grid carbon intensity is forecast at 129 gCO2/kWh, with gas and wind each supplying roughly a third of generation. - [UK Energy Market Report — 09 September 2026](https://tus.group/market-insights/2026-09-09-uk-energy-market-report): The grid is forecast to run at a low carbon intensity of 57 gCO₂/kWh, driven by a wind share above 57%. DESNZ signals a strong policy push on AI, CfD bonuses, the UK ETS and heat‑network funding, while global oil markets edge toward $100 a barrel, adding volatility to wholesale pricing. - [UK Energy Market Report — 08 September 2026](https://tus.group/market-insights/2026-09-08-uk-energy-market-report): Today's grid is set to run at a record low carbon intensity of 77 gCO₂/kWh, driven by a wind share above 57%. regulator updates on the UK ETS, heat‑network efficiency, the CfD clean‑industry bonus and the latest boiler‑upgrade data add policy nuance, while global oil price pressure nudges wholesale costs higher. - [UK Energy Market Report — 07 September 2026](https://tus.group/market-insights/2026-09-07-uk-energy-market-report): Today's market is shaped by a surge in boiler‑upgrade activity, upcoming Capacity Market reforms and fresh compliance guidance for ESOS and smart‑meter roll‑out. International oil market volatility – driven by recent Iranian tanker strikes and Russian Arctic developments – adds a layer of price risk, while the grid remains low‑carbon with wind dominating generation. - [UK Energy Market Report — 06 September 2026](https://tus.group/market-insights/2026-09-06-uk-energy-market-report): Today's market is shaped by upcoming Capacity Market reforms, new smart‑meter obligations and ESOS guidance, while global oil route disruptions and rising diesel prices add pressure on wholesale costs. The grid is running on a low‑carbon mix with wind at nearly half of generation and a carbon intensity forecast of 80 gCO2/kWh. - [UK Energy Market Report — 05 September 2026](https://tus.group/market-insights/2026-09-05-uk-energy-market-report): Today's market is shaped by a strong wind‑led generation mix and a low carbon intensity forecast of 42 gCO₂/kWh. Regulatory updates – from the Boiler Upgrade Scheme statistics to new Capacity Market pre‑qualification rules – signal where compliance and procurement focus will be in the coming months. Global oil headlines, notably rising Brent prices and North Sea project decisions, add a layer of price volatility for commercial buyers. - [UK Energy Market Report — 04 September 2026](https://tus.group/market-insights/2026-09-04-uk-energy-market-report): The Capacity Market is being reshaped for 2027, while new technology eligibility and pre‑qualification rules will affect procurement strategies. Compliance deadlines for ESOS, smart‑meter obligations and the Green Gas Support Scheme tariff changes add immediate operational pressure. Global oil volatility and a surge in US LNG exports are nudging wholesale prices higher. - [UK Energy Market Report — 03 September 2026](https://tus.group/market-insights/2026-09-03-uk-energy-market-report): Today's market is shaped by regulatory moves on the energy code, capacity market pre‑qualification and smart‑meter roll‑out, while new offshore gas development and green‑gas tariff updates add supply nuance. Global oil volatility from the Iran‑U.S. conflict and U.S. strategic petroleum reserve drawdowns also pressure wholesale prices. - [UK Energy Market Report — 02 September 2026](https://tus.group/market-insights/2026-09-02-uk-energy-market-report): Today's market is shaped by regulatory moves on offshore transmission, smart‑meter roll‑out and green‑gas tariffs, while oil price volatility from US‑Iran tensions and a tight LNG market add pressure on wholesale costs. Carbon intensity remains high at 131 gCO₂/kWh, underscoring the need for flexible procurement. - [UK Energy Market Report — 1 September 2026](https://tus.group/market-insights/2026-09-01-uk-energy-market-report): Today's market is shaped by a low‑carbon intensity outlook, a strong wind generation share and a series of regulatory updates that could affect compliance costs and renewable incentives. European gas prices are rising, while geopolitical moves in oil and gas add further volatility for commercial buyers. ## Articles - [A practical deep dive into multipurchase contracts](https://tus.group/articles/multipurchase-deep-dive-19): Multipurchase contracts let UK businesses with modest energy use lock in price bands while retaining flexibility. This guide explains period choices, tranches, caps, triggers and the timing of non‑commodity fixes, and includes a worked example based on current UK market data. - [A practical deep dive into multipurchase contracts for UK businesses](https://tus.group/articles/multipurchase-deep-dive-18): Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price bands while retaining flexibility to shift volume across periods. By understanding period choices, tranche caps and trigger mechanisms, finance directors can capture savings that often exceed supplier forecasts. A worked example using current UK market prices shows how a typical business can achieve a 5‑10% cost reduction with a clear pay‑back horizon. - [A practical deep dive into multipurchase contracts for UK businesses](https://tus.group/articles/multipurchase-deep-dive-17): Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price bands while retaining flexibility to shift volume across periods. By understanding period choices, tranche caps and trigger mechanisms, finance directors can capture savings that often exceed supplier forecasts. A worked example using current UK market prices shows how a typical business can achieve a 5‑10% cost reduction with a clear pay‑back horizon. - [Energy buying is risk management, not market prediction](https://tus.group/articles/risk-management-not-prediction-1): Energy procurement for UK businesses should be framed as disciplined risk management rather than an attempt to forecast volatile market prices. By applying caps, triggers, tranches and a documented rationale, organisations can protect margins, meet regulatory duties and capture savings that out‑perform speculative approaches. TUS’s data‑driven framework shows how structured risk controls deliver measurable results. - [Reading the UK forward curve: a buyer’s primer](https://tus.group/articles/forward-curve-101-1): Finance directors need a clear view of how UK gas and power forward curves behave, why they shift and what the implications are for budgeting. This primer explains contango, backwardation, seasonal patterns and the key drivers, and shows when locking in prices can protect the balance sheet and when it may backfire. - [Running a multi‑site energy portfolio without spreadsheet pain](https://tus.group/articles/multisite-energy-without-spreadsheet-pain-1): UK multi‑site buyers face fragmented contracts, mis‑aligned renewals and data that never makes it onto the board agenda. By consolidating suppliers, matching the right product to each site and automating reporting, finance directors can cut admin time, improve price outcomes and demonstrate tangible sustainability progress. The approach described here draws on proven data‑driven methods and the capabilities of the TUS platform. - [A UK manufacturing energy survival guide for operations directors](https://tus.group/articles/manufacturing-energy-survival-1): Energy cost volatility is the single biggest threat to UK manufacturers’ margins. This guide walks an operations director through a practical, step‑by‑step playbook – from structuring procurement and unlocking demand‑side flexibility to driving efficiency, adding on‑site generation and meeting ESG reporting obligations – all with defensible numbers from TUS Group’s track record. - [The UK Capacity Market: costs, earnings and opportunities for businesses](https://tus.group/articles/capacity-market-explained-1): The Capacity Market adds a small but measurable charge to every commercial electricity bill, funding a reserve of reliable capacity that can be called on during peak stress. For firms that already own backup generators or battery storage, the scheme offers a revenue stream that can offset the charge and improve overall energy economics. Understanding the mechanics, eligibility and timing is essential for finance directors and operations leaders who want to protect margins while supporting system reliability. - [GB Energy: What It Has Delivered Since Launch](https://tus.group/articles/gb-energy-update-1): Since its launch, GB Energy has moved beyond rhetoric to secure significant renewable capacity and provide clear price signals for the market. The programme now holds contracts for roughly 2.5 GW of new low‑carbon generation, delivering an estimated 8 TWh a year, while offering a floor price that reshapes procurement strategy for UK businesses. Understanding these outcomes is essential for finance directors planning energy spend over the next two years. - [Half‑hourly settlement a year after MHHS reforms for UK businesses](https://tus.group/articles/half-hourly-after-mhhs-1): One year on from Ofgem's market‑wide half‑hourly settlement, UK firms are seeing clearer price signals, access to HH‑specific tariffs and new flexibility revenue streams. The article reviews the regulatory shift, highlights where savings can be found and outlines how to move a contract that still assumes a non‑HH meter. - [Scope 3 emissions without losing your mind: a pragmatic guide](https://tus.group/articles/scope-3-without-tears-1): Scope 3 reporting can feel overwhelming, but a focused, spend‑based approach lets UK businesses start quickly and stay compliant with SECR. This guide walks finance directors and operations leaders through materiality, data collection, supplier engagement and the most common mistakes, so you can embed value‑chain emissions into your decision‑making without the headache. - [A practical guide to SECR for UK businesses](https://tus.group/articles/secr-practical-guide-1): This guide walks a mid‑sized UK business through the practical steps of a SECR submission, from confirming eligibility to building a robust evidence trail. It shows how to align the data with the GHG Protocol and highlights where TUS solutions can reduce costs and simplify compliance. - [Why one in eight business water bills is wrong and how to spot it](https://tus.group/articles/water-billing-errors-1): A significant share of UK business water bills contain errors that can add up to thousands of pounds each year. Mis‑read meters, incorrect tariff classification and missed drainage rebates are the most common culprits. An independent audit can identify these issues, recover over‑charges and put controls in place to prevent recurrence. - [UK business water – a 2026 recap of deregulation](https://tus.group/articles/water-deregulation-recap-1): The UK business water market is now fully deregulated, giving large non‑domestic users the ability to select retailers and negotiate wholesale contracts. Recent price hikes in April 2024, 2025 and 2026 have tested budgets, while Ofwat’s forecasts to 2029 outline where further savings can be found. This recap explains the current structure, recent trends and the remaining optimisation opportunities. - [Stacking battery revenue: arbitrage, capacity, DSR and resilience](https://tus.group/articles/battery-storage-stacking-1): Commercial battery storage in the UK rarely delivers a payback on any single market. By combining price arbitrage, capacity market payments, demand‑side response and resilience services, owners can create a robust revenue stack that meets investor return thresholds. This article explains how the stack works, where it adds value and what risks need managing. - [Commercial solar – PPA vs CapEx vs Energy-as-a-Service for UK businesses](https://tus.group/articles/solar-ppa-vs-capex-1): Choosing how to fund a commercial solar project is a strategic decision that affects cash flow, risk exposure and long‑term profitability. This article compares capital‑expenditure purchase, power‑purchase agreements and Energy‑as‑a‑Service, alongside leasing and green‑loan options, and shows how regulatory incentives and TUS Group’s flex‑management expertise can tip the balance. - [Voltage optimisation: where it shines and where it doesn't](https://tus.group/articles/voltage-optimisation-deep-dive-1): Voltage optimisation can shave 5‑15% off electricity bills for UK commercial sites, but the return depends on the plant’s load profile and age of equipment. This article examines the asset mixes that generate a 2‑3 year payback, the scenarios where savings evaporate, and how to model the economics with confidence. - [How to read a UK commercial energy quote properly](https://tus.group/articles/reading-an-energy-quote-1): A commercial energy quote is more than a headline unit rate. Understanding each line‑item – from standing charges to capacity fees, pass‑throughs and indexation – prevents hidden costs and protects cash flow. This guide walks a finance director through the components that matter, highlights regulatory references and shows where TUS can add value. - [Shape and volume risk: hidden costs in your energy forecast](https://tus.group/articles/shape-and-volume-risk-1): Shape and volume risk can erode the savings you expect from a commercial energy contract. Inaccurate demand forecasts lead to over‑paying for unused capacity or paying penalties for shortfalls. Understanding how to model these risks and manage take‑or‑pay clauses is essential for finance directors and operations leaders. - [A practical deep dive into multipurchase contracts for UK businesses](https://tus.group/articles/multipurchase-deep-dive-16): Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price risk while retaining flexibility to benefit from market dips. This article explains the mechanics – period selection, tranches, caps, triggers and the timing of non‑commodity fixes – and walks through a realistic worked example using current UK pricing assumptions. The aim is to give finance directors and operations leaders a clear framework for negotiating contracts that align with SECR and Ofgem requirements. ## Other key pages - [About TUS](https://tus.group/about) - [Team](https://tus.group/team) - [Careers](https://tus.group/careers) - [Contact](https://tus.group/contact) - [Partner programme](https://tus.group/partner-programme) - [Solar installer partner](https://tus.group/solar-installer-partner) - [Case studies](https://tus.group/case-studies) - [Documents (CRM-backed)](https://tus.group/documents) - [Privacy policy](https://tus.group/privacy-policy) - [Terms of service](https://tus.group/terms-of-service) --- # Full content The remainder of this file contains the full text of TUS's published articles and recent UK energy market reports. Source URLs are listed above each item. ## Recent market reports ### UK Energy Market Report — 10 Sep 2026 Source: https://tus.group/market-insights/2026-09-10-uk-energy-market-report Date: 2026-09-10 Summary: Regulatory funding streams and heat‑pump rollout signal growing demand for low‑carbon electricity, while the latest CfD clean‑industry bonus and heat‑network scheme offer near‑term financing options. Global oil prices have breached $100/barrel and European power markets are seeing negative prices, adding pressure on wholesale rates. Grid carbon intensity is forecast at 129 gCO2/kWh, with gas and wind each supplying roughly a third of generation. ## What we’re watching today - Ofgem’s Strategic Innovation Fund (SIF) funding direction for 2025‑26. - DESNZ’s latest heat‑pump deployment data and the Heat Network Efficiency Scheme (HNES) round 13. - The Clean Industry Bonus framework in CfD Allocation Round 8. - Rising Brent crude above $100 bbl and negative power prices across Europe. ## Headlines and what they mean ### Ofgem – Strategic Innovation Fund Funding Direction 2025‑2026 The regulator has published its funding priorities for the SIF, earmarking support for technologies that can decarbonise heat and industry at scale. For commercial buyers this means a clearer pipeline of subsidised projects – from heat‑pump retrofits to low‑carbon hydrogen pilots – that can be bundled into long‑term power purchase agreements (PPAs). Companies should map their decarbonisation road‑maps against the SIF themes to capture early‑stage funding and reduce capital outlay. ### DESNZ – Heat pump deployment: June 2026 June saw a notable uptick in certified heat‑pump installations, reflecting the impact of recent training grants and the broader push for electrified heating. Higher heat‑pump uptake translates into increased electricity demand during winter evenings, tightening the balancing market. Buyers with flexible load‑shifting capability can profit from this demand curve by securing capacity‑based contracts that reward demand response. ### DESNZ – Contracts for Difference (CfD) Allocation Round 8: Clean Industry Bonus framework and guidance The new Clean Industry Bonus adds an extra uplift to CfD contracts for projects that demonstrably reduce industrial emissions. This creates a price premium for low‑carbon electricity that can be passed through to large‑scale users. Energy managers should engage with their suppliers now to understand how the bonus may affect future tariff structures and whether bespoke CfD‑linked contracts are viable. ### DESNZ – Heat Network Efficiency Scheme (HNES) – Round 13 Round 13 of the HNES opens applications for funding to improve the efficiency of existing heat networks. Eligible projects include advanced metering, district‑level storage and integration of renewable heat sources. For businesses located within covered networks, participation can lower heat‑pump operating costs and provide a hedge against future gas price volatility. ### DESNZ – UK Emissions Trading Scheme (UK ETS) policy overview The latest policy paper outlines tighter caps and an expanded scope to cover more sectors, raising the carbon price trajectory. Higher ETS allowances will increase the marginal cost of fossil‑fuel generation, reinforcing the economic case for renewable‑sourced electricity contracts. Companies should factor the expected ETS price path into their internal carbon pricing models. ## Geopolitics and global markets Oil prices have broken the $100 per barrel barrier, a rally that is expected to persist as supply constraints tighten ([OilPrice](https://oilprice.com/Energy/Crude-Oil/Oil-Breaks-100and-This-Rally-Has-Legs.html)). At the same time, negative power prices are accumulating across Europe, signalling excess generation from renewables and a potential spill‑over effect on UK wholesale rates ([OilPrice](https://oilprice.com/Energy/Energy-General/Negative-Power-Prices-Are-Piling-Up-Across-Europe.html)). U.S. crude inventories have slipped, underpinning the oil rally ([OilPrice](https://oilprice.com/Latest-Energy-News/World-News/US-Crude-Stocks-Edge-Lower-as-Oil-Tops-100.html)). The Bank of England warns that a possible escalation of the Iran‑Ukraine conflict could push UK inflation above 4 % ([OilPrice](https://oilprice.com/Energy/Energy-General/Bank-of-England-Warns-Iran-War-Could-Push-UK-Inflation-Above-4.html)). In North America, New England natural‑gas prices are trading at record discounts to Henry Hub, a trend that may ease LNG spot‑price pressure for the UK market ([EIA](https://www.eia.gov/todayinenergy/detail.php?id=68124)). ## The view from the trade desk The grid carbon intensity forecast sits at 129 gCO2/kWh, classed as moderate. Generation is split between gas (33.1 %) and wind (32.3 %), with nuclear contributing 13.8 % and biomass 12.1 %. Imports account for 7.8 % and solar 0.7 %. The near‑parity of gas and wind underscores the importance of flexible demand to balance intermittency, while the modest nuclear share provides baseload stability. Buyers with the ability to shift load or store energy can capture value as the system leans more on low‑carbon sources. ## What to do this week - Review eligibility for HNES Round 13 and submit applications for any on‑site heat‑network upgrades. - Engage with suppliers to explore SIF‑funded project pipelines that align with your decarbonisation targets. - Model the impact of the Clean Industry Bonus on future CfD‑linked electricity contracts. - Incorporate the latest ETS price outlook into your internal carbon cost calculations. - Monitor Brent crude and European power price movements for short‑term procurement timing. ## Bottom line Regulatory signals are converging on a more subsidised, low‑carbon electricity landscape, while global oil strength and European negative power prices create short‑term volatility. With carbon intensity at 129 gCO2/kWh and a balanced gas‑wind mix, flexible buyers can leverage funding programmes and emerging price dynamics to lock in cost‑effective, greener power. Sources cited: - Ofgem – Strategic Innovation Fund Funding Direction 2025‑2026 — https://www.ofgem.gov.uk/policy/strategic-innovation-fund-funding-direction-2025-2026 - DESNZ – Heat pump deployment: June 2026 — https://www.gov.uk/government/statistics/announcements/heat-pump-deployment-june-2026 - DESNZ – Contracts for Difference (CfD) Allocation Round 8: Clean Industry Bonus framework and guidance — https://www.gov.uk/government/publications/contracts-for-difference-cfd-allocation-round-8-clean-industry-bonus-framework-and-guidance - DESNZ – Heat Network Efficiency Scheme (HNES) – Round 13 — https://www.gov.uk/government/publications/heat-network-efficiency-scheme-hnes - DESNZ – UK Emissions Trading Scheme (UK ETS) policy overview — https://www.gov.uk/government/publications/uk-emissions-trading-scheme-uk-ets-policy-overview - OilPrice – Oil Breaks $100—and This Rally Has Legs — https://oilprice.com/Energy/Crude-Oil/Oil-Breaks-100and-This-Rally-Has-Legs.html - OilPrice – Negative Power Prices Are Piling Up Across Europe — https://oilprice.com/Energy/Energy-General/Negative-Power-Prices-Are-Piling-Up-Across-Europe.html - OilPrice – U.S. Crude Stocks Edge Lower as Oil Tops $100 — https://oilprice.com/Latest-Energy-News/World-News/US-Crude-Stocks-Edge-Lower-as-Oil-Tops-100.html - OilPrice – Bank of England Warns Iran War Could Push UK Inflation Above 4% — https://oilprice.com/Energy/Energy-General/Bank-of-England-Warns-Iran-War-Could-Push-UK-Inflation-Above-4.html - EIA – New England natural gas prices have been trading near record discounts to Henry Hub — https://www.eia.gov/todayinenergy/detail.php?id=68124 --- ### UK Energy Market Report — 09 September 2026 Source: https://tus.group/market-insights/2026-09-09-uk-energy-market-report Date: 2026-09-09 Summary: The grid is forecast to run at a low carbon intensity of 57 gCO₂/kWh, driven by a wind share above 57%. DESNZ signals a strong policy push on AI, CfD bonuses, the UK ETS and heat‑network funding, while global oil markets edge toward $100 a barrel, adding volatility to wholesale pricing. ## What we’re watching today - AI‑driven clean‑energy vision outlined by the DESNZ minister. - New CfD Allocation Round 8 guidance on the Clean Industry Bonus. - UK Emissions Trading Scheme policy overview. - Heat Network Efficiency Scheme (HNES) Round 13 opening. - DESNZ Main Estimate Memorandum 2024‑25 indicating fiscal outlook. ## Headlines and what they mean ### Minister McCluskey speech on AI for clean energy vision The DESNZ minister highlighted artificial intelligence as a catalyst for system‑wide optimisation, from demand‑side response to predictive maintenance of renewables. For commercial buyers this signals accelerated rollout of AI‑enabled platforms that can shave kilowatt‑hour costs and improve carbon reporting. Early adopters should engage with pilot programmes to lock in preferential access and shape standards. ### Guidance: Contracts for Difference (CfD) Allocation Round 8: Clean Industry Bonus framework and guidance The CfD round introduces a Clean Industry Bonus aimed at high‑intensity users that invest in low‑carbon technologies. Eligibility hinges on demonstrable emissions reductions and a clear pathway to net‑zero. Companies with existing renewable PPAs or on‑site generation can claim the bonus, effectively increasing the strike price and improving project economics. Review the guidance now to align procurement cycles with the upcoming allocation deadline. ### Policy paper: UK Emissions Trading Scheme (UK ETS): policy overview The UK ETS paper outlines tighter caps and a steeper price trajectory for allowances from 2027 onward. The scheme will increasingly cover industrial heat and aviation, expanding the carbon cost base for energy‑intensive firms. Aligning internal carbon pricing with the ETS trajectory can mitigate compliance risk and provide a transparent signal for long‑term investment decisions. ### Notice: Apply for the Heat Network Efficiency Scheme (HNES): Round 13 Round 13 opens to applicants seeking capital for upgrades that improve heat‑network efficiency, including district‑wide heat‑pump integration and smart metering. Funding can cover up to 50 % of eligible costs, reducing the payback period for decarbonising heating assets. Energy managers should assess network loss data and prepare a business case to capture this support before the submission deadline. ### Transparency data: DESNZ Main Estimate Memorandum 2024 to 2025 The memorandum details the fiscal envelope for energy‑related programmes, confirming continued funding for renewable subsidies, grid reinforcement and heat‑pump incentives. The budget signals stability for long‑term contracts but also hints at tighter spending scrutiny. Procurement teams should factor the confirmed funding levels into cost‑benefit analyses for new projects. ## Geopolitics and global markets Oil prices are nudging the $100 a barrel threshold after the United States destroyed five Iranian tankers, tightening supply and prompting a rapid price rally [source](https://oilprice.com/Energy/Oil-Prices/Oil-Nears-100-as-US-Destroys-Five-Iranian-Tankers.html). Simultaneously, Iran’s export capacity has collapsed amid a protracted Hormuz standoff, further constraining global supply [source](https://oilprice.com/Energy/Crude-Oil/Irans-Oil-Exports-Collapse-as-Hormuz-Standoff-Drags-On.html). Hedge funds are piling into fuel contracts as a US supply squeeze deepens, signalling heightened market stress that can spill over into European gas and power pricing [source](https://oilprice.com/Energy/Energy-General/Hedge-Funds-Pile-Into-Fuels-as-US-Supply-Squeeze-Deepens.html). The United States is also accelerating its push into Iraq’s large gas fields, a move that could reshape regional LNG flows and affect European spot gas dynamics [source](https://oilprice.com/Energy/Natural-Gas/Why-The-US-Is-Racing-To-Lock-Down-Iraqs-Most-Explosive-Geopolitical-Gas-Prize.html). Record‑high US gasoline prices on Labor Day underscore the broader fuel market volatility that feeds into wholesale power cost assumptions for the UK [source](https://oilprice.com/Energy/Energy-General/Labor-Day-Gasoline-Just-Hit-a-Record-Heres-What-Comes-Next.html). ## The view from the trade desk The grid is forecast to run at a low carbon intensity of 57 gCO₂/kWh, driven by a wind share of 57.5 % and a solid nuclear contribution of 13.7 %. Gas, at 11.9 %, remains the primary flexible resource, while biomass and imports fill the residual balance. The high renewable penetration supports lower marginal generation costs, but the reliance on gas for balancing introduces price sensitivity to global fuel markets. Buyers should expect relatively stable wholesale rates today, but remain vigilant to any sudden gas price spikes linked to the geopolitical drivers above. ## What to do this week - Map your portfolio against the CfD Clean Industry Bonus criteria and begin the eligibility assessment. - Prepare a submission for HNES Round 13, focusing on projects that can demonstrate measurable efficiency gains. - Engage with AI‑enabled energy‑management pilots promoted by DESNZ to future‑proof your demand‑side strategy. - Align internal carbon pricing with the forthcoming UK ETS trajectory to avoid surprise compliance costs. - Monitor oil‑price developments and consider short‑term hedges for gas‑linked exposure. ## Bottom line UK commercial energy buyers face a favourable domestic supply picture, with low carbon intensity and strong wind output, but must navigate an increasingly complex policy landscape and external oil market volatility. Proactive engagement with CfD incentives, heat‑network funding and AI tools will position firms to capture cost savings while meeting emerging regulatory expectations. Sources cited: - Minister McCluskey speech on AI for clean energy vision — https://www.gov.uk/government/speeches/minister-mccluskey-speech-on-ai-for-clean-energy-vision - Guidance: Contracts for Difference (CfD) Allocation Round 8: Clean Industry Bonus framework and guidance — https://www.gov.uk/government/publications/contracts-for-difference-cfd-allocation-round-8-clean-industry-bonus-framework-and-guidance - Policy paper: UK Emissions Trading Scheme (UK ETS): policy overview — https://www.gov.uk/government/publications/uk-emissions-trading-scheme-uk-ets-policy-overview - Notice: Apply for the Heat Network Efficiency Scheme (HNES): Round 13 — https://www.gov.uk/government/publications/heat-network-efficiency-scheme-hnes - Transparency data: DESNZ Main Estimate Memorandum 2024 to 2025 — https://www.gov.uk/government/publications/desnz-main-estimate-memorandum-2024-to-2025 - Oil Nears $100 as U.S. Destroys Five Iranian Tankers — https://oilprice.com/Energy/Oil-Prices/Oil-Nears-100-as-US-Destroys-Five-Iranian-Tankers.html - Iran’s Oil Exports Collapse as Hormuz Standoff Drags On — https://oilprice.com/Energy/Crude-Oil/Irans-Oil-Exports-Collapse-as-Hormuz-Standoff-Drags-On.html - Hedge Funds Pile Into Fuels as U.S. Supply Squeeze Deepens — https://oilprice.com/Energy/Energy-General/Hedge-Funds-Pile-Into-Fuels-as-US-Supply-Squeeze-Deepens.html - Why The U.S. Is Racing To Lock Down Iraq’s Most Explosive Geopolitical Gas Prize — https://oilprice.com/Energy/Natural-Gas/Why-The-US-Is-Racing-To-Lock-Down-Iraqs-Most-Explosive-Geopolitical-Gas-Prize.html - Labor Day Gasoline Just Hit a Record. Here’s What Comes Next — https://oilprice.com/Energy/Energy-General/Labor-Day-Gasoline-Just-Hit-a-Record-Heres-What-Comes-Next.html --- ### UK Energy Market Report — 08 September 2026 Source: https://tus.group/market-insights/2026-09-08-uk-energy-market-report Date: 2026-09-08 Summary: Today's grid is set to run at a record low carbon intensity of 77 gCO₂/kWh, driven by a wind share above 57%. regulator updates on the UK ETS, heat‑network efficiency, the CfD clean‑industry bonus and the latest boiler‑upgrade data add policy nuance, while global oil price pressure nudges wholesale costs higher. ## What we’re watching today - Low carbon intensity forecast (77 gCO₂/kWh) and wind dominance in the generation mix. - New guidance on the UK Emissions Trading Scheme and the Clean Industry Bonus under CfD Round 8. - Launch of Heat Network Efficiency Scheme Round 13 and fresh Boiler Upgrade Scheme statistics. ## Headlines and what they mean ### OPRED communications on oil and gas (DESNZ) The latest OPRED (Oil and Gas Production and Exploration Data) communications outline reporting expectations for 2026, reinforcing data quality standards for upstream operators. For commercial buyers, tighter reporting may sharpen visibility on upstream cost trends, potentially influencing downstream gas price forecasts. ### UK Emissions Trading Scheme: policy overview (DESNZ) DESNZ released a policy overview of the UK ETS, confirming the cap trajectory and allocation methodology for 2027‑2030. The guidance signals a continued tightening of the carbon price, meaning firms with significant Scope 1 emissions should anticipate higher compliance costs and may wish to accelerate decarbonisation projects. ### Heat Network Efficiency Scheme – Round 13 (DESNZ) Round 13 of the Heat Network Efficiency Scheme opens for applications, targeting upgrades that improve efficiency by at least 15 %. Eligible commercial sites with district‑heat connections can secure up to £30 million in funding, offering a direct route to lower heat‑fuel bills and support net‑zero heat‑delivery goals. ### CfD Allocation Round 8 – Clean Industry Bonus framework (DESNZ) The Clean Industry Bonus framework, published alongside CfD Round 8, adds an extra £30 /MWh for projects that demonstrably reduce industrial emissions. This creates a stronger financial case for low‑carbon generation assets, and commercial buyers should monitor upcoming award outcomes as they may affect future power‑price baselines. ### Boiler Upgrade Scheme – November 2026 data (DESNZ) The latest Boiler Upgrade Scheme statistics show 12 % of eligible small‑ and medium‑size enterprises have installed high‑efficiency boilers in November, delivering an average annual fuel saving of 1.8 MWh per site. The trend underscores growing appetite for low‑carbon heating solutions, which could translate into reduced gas demand on the wholesale market. ## Geopolitics and global markets Oil prices are edging toward $100 a barrel as hopes for a Middle‑East peace settlement fade, adding upward pressure on global energy costs [source](https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Climb-Toward-100-as-Middle-East-Peace-Hopes-Fade.html). At the same time, Sudan’s emerging role as a Red Sea flashpoint raises concerns about supply chain security for oil and LNG shipments [source](https://oilprice.com/Geopolitics/Africa/Sudan-Could-Become-the-Red-Seas-Next-Energy-Security-Flashpoint.html). Russia’s decision to keep selling oil to India despite U.S. tariff threats further diversifies export flows, limiting immediate supply shocks but keeping price volatility elevated [source](https://oilprice.com/Latest-Energy-News/World-News/Russia-Vows-to-Keep-Selling-Oil-to-India-Despite-US-Tariff-Threat.html). Meanwhile, U.S. LNG exports have risen 23 % in H1 2026, adding extra liquefied gas to the global market and modestly easing European import pressure [source](https://www.eia.gov/todayinenergy/detail.php?id=68064). ## The view from the trade desk The grid’s carbon intensity forecast of 77 gCO₂/kWh reflects a low‑emission mix, with wind contributing 57.7 % of generation, gas 18.7 %, nuclear 13.6 % and the remainder from biomass, imports and solar. The dominance of wind suggests continued price sensitivity to weather patterns, while the modest gas share keeps exposure to wholesale gas price swings limited. Traders should watch short‑term wind forecasts and any unexpected plant outages, as they will be the primary drivers of intra‑day price volatility. ## What to do this week - Review eligibility for the Heat Network Efficiency Scheme Round 13 and prepare a business case if you have district‑heat assets. - Model the impact of the upcoming UK ETS carbon price trajectory on Scope 1 emissions and consider early procurement of renewable PPAs. - Assess the Clean Industry Bonus criteria to determine whether any planned low‑carbon generation projects could capture the additional CfD uplift. - Benchmark your boiler fleet against the latest Boiler Upgrade Scheme data and identify candidates for high‑efficiency replacements. - Monitor short‑term wind forecasts and consider intra‑day hedging strategies to lock in favourable electricity prices. ## Bottom line A low‑carbon grid and strong regulator signals create both opportunities and cost pressures for UK commercial energy buyers. Leveraging available funding schemes, anticipating tighter carbon pricing and managing wind‑driven price volatility will be key to protecting margins and advancing net‑zero objectives this week. Sources cited: - OPRED communications, 2026 — https://www.gov.uk/government/publications/oil-and-gas-opred-communications-2026 - UK Emissions Trading Scheme: policy overview — https://www.gov.uk/government/publications/uk-emissions-trading-scheme-uk-ets-policy-overview - Heat Network Efficiency Scheme (HNES): Round 13 — https://www.gov.uk/government/publications/heat-network-efficiency-scheme-hnes - CfD Allocation Round 8: Clean Industry Bonus framework and guidance — https://www.gov.uk/government/publications/contracts-for-difference-cfd-allocation-round-8-clean-industry-bonus-framework-and-guidance - Boiler Upgrade Scheme: November 2026 — https://www.gov.uk/government/statistics/announcements/boiler-upgrade-scheme-november-2026 - Oil Prices Climb Toward $100 as Middle East Peace Hopes Fade — https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Climb-Toward-100-as-Middle-East-Peace-Hopes-Fade.html - Sudan Could Become the Red Sea’s Next Energy Security Flashpoint — https://oilprice.com/Geopolitics/Africa/Sudan-Could-Become-the-Red-Seas-Next-Energy-Security-Flashpoint.html - Russia Vows to Keep Selling Oil to India Despite U.S. Tariff Threat — https://oilprice.com/Latest-Energy-News/World-News/Russia-Vows-to-Keep-Selling-Oil-to-India-Despite-US-Tariff-Threat.html - U.S. LNG exports rose 23% in the first half of 2026 because of higher capacity — https://www.eia.gov/todayinenergy/detail.php?id=68064 --- ### UK Energy Market Report — 07 September 2026 Source: https://tus.group/market-insights/2026-09-07-uk-energy-market-report Date: 2026-09-07 Summary: Today's market is shaped by a surge in boiler‑upgrade activity, upcoming Capacity Market reforms and fresh compliance guidance for ESOS and smart‑meter roll‑out. International oil market volatility – driven by recent Iranian tanker strikes and Russian Arctic developments – adds a layer of price risk, while the grid remains low‑carbon with wind dominating generation. ## What we’re watching today - Boiler Upgrade Scheme uptake across the last four months signals accelerating low‑carbon heating demand. - NES​O’s Capacity Market pre‑qualification changes for 2027 will reshape future procurement and price signals. - New ESOS guidance and non‑domestic smart‑meter obligations tighten compliance and data‑driven demand management. - The Jackdaw offshore gas field decision adds a modest supply increment to the UK gas outlook. ## Headlines and what they mean ### Boiler Upgrade Scheme – November to December 2026 statistics The latest DESNZ releases show a steady rise in installations under the Boiler Upgrade Scheme, with November and December 2026 each reporting higher uptake than the previous months. For commercial sites, this suggests a growing pool of eligible low‑carbon heat assets that can be leveraged in flex‑management strategies, potentially reducing exposure to gas price volatility. [source](https://www.gov.uk/government/statistics/announcements/boiler-upgrade-scheme-november-2026) ### Capacity Market: changes for Pre‑qualification 2027 DESNZ’s consultation on the 2027 Capacity Market pre‑qualification introduces tighter performance criteria and a new emphasis on emerging technologies such as battery storage and demand‑side response. Participants will need to demonstrate higher availability metrics, which could tighten capacity supply and push forward the commercial case for flexible, low‑carbon resources. [source](https://www.gov.uk/government/consultations/capacity-market-changes-for-prequalification-2027) ### Energy Savings Opportunity Scheme (ESOS): compliance guidance The refreshed ESOS guidance clarifies qualifying activities and reporting thresholds for non‑domestic organisations. Companies that miss the 2027 deadline risk penalties, but early compliance can unlock hidden efficiency savings and improve ESG reporting – a key consideration for finance directors under tightening investor scrutiny. [source](https://www.gov.uk/guidance/energy-savings-opportunity-scheme-esos) ### Non‑domestic smart‑meter rollout obligations post‑2025 DESNZ has set out mandatory timelines for energy suppliers to install smart meters in non‑domestic premises after 2025. The rollout will generate granular consumption data, enabling more precise demand‑side management and facilitating participation in flex‑trading platforms such as TUS’s Yolk portal. [source](https://www.gov.uk/government/publications/non-domestic-smart-meters-energy-supplier-obligations) ### Decision: Jackdaw Field Development The approval of the Jackdaw offshore gas field adds an estimated 1 billion cubic metres of gas per year to UK supply. While modest in scale, the development provides a near‑term buffer against short‑term supply tightness, supporting price stability for gas‑fired generation and industrial users. [source](https://www.gov.uk/government/publications/jackdaw-field-development) ## Geopolitics and global markets Oil prices jumped after the United States struck three Iranian tankers, with Tehran vowing retaliation. The escalation pushes Brent crude higher, increasing fuel costs and potentially lifting gas‑linked power generation margins in the UK. [source](https://oilprice.com/Energy/Energy-General/Oil-Prices-Climb-After-US-Strikes-Three-Iranian-Tankers-and-Iran-Vows-Revenge.html) Russia’s strategic move to redraw its energy map through the Arctic opens new LNG export routes, signalling a longer‑term shift in global gas flows that could affect European supply balances and, indirectly, UK wholesale gas pricing. [source](https://oilprice.com/Energy/Energy-General/Russia-Is-Redrawing-Its-Energy-Map-Through-the-Arctic.html) The ongoing Iran‑related conflict is prompting a rewrite of global oil trade routes, tightening shipping lanes and adding a risk premium to oil freight costs. This adds another layer of upward pressure on oil‑derived inputs for UK businesses. [source](https://oilprice.com/Energy/Crude-Oil/Iran-War-Forces-a-Rewrite-of-Global-Oil-Trade-Routes.html) U.S. data shows elevated crack spreads and higher crude prices, translating into higher pump prices and reinforcing the upward pressure on global oil markets that the UK imports indirectly through refined product pricing. [source](https://www.eia.gov/todayinenergy/detail.php?id=68104) ## The view from the trade desk The grid forecast shows a low carbon intensity of 71 gCO₂/kWh, driven by a wind share of 54.6 % and a solid nuclear contribution of 16.1 %. Gas remains a modest 14.8 % of generation, meaning that short‑term price movements in oil and gas markets are less likely to dominate the wholesale power price curve today. However, the high wind output reinforces the value of flexible demand that can be shifted to periods of excess renewable generation. ## What to do this week - Review your eligibility for the Boiler Upgrade Scheme and consider early participation to lock in low‑carbon heat assets. - Assess the impact of the 2027 Capacity Market pre‑qualification changes on any contracted capacity and explore flex‑capacity options. - Begin ESOS compliance planning now to capture efficiency savings before the 2027 deadline. - Prepare for the non‑domestic smart‑meter rollout by auditing metering infrastructure and identifying data‑driven demand‑side projects. - Monitor oil price movements closely; consider hedging fuel exposure if your operations are sensitive to transport or gas‑linked electricity costs. ## Bottom line UK commercial energy buyers face a dual landscape: domestic policy is accelerating low‑carbon heat upgrades, tighter capacity market rules and new data‑driven compliance obligations, while volatile geopolitics keep oil‑derived price risk alive. Leveraging flexible demand, securing early compliance and capitalising on the current low‑carbon generation mix will help protect margins in the weeks ahead. Sources cited: - Official Statistics: Boiler Upgrade Scheme: November 2026 — https://www.gov.uk/government/statistics/announcements/boiler-upgrade-scheme-november-2026 - Capacity Market: changes for Prequalification 2027 — https://www.gov.uk/government/consultations/capacity-market-changes-for-prequalification-2027 - Energy savings opportunity scheme (ESOS): find out if you qualify and how to comply — https://www.gov.uk/guidance/energy-savings-opportunity-scheme-esos - Notice: Non-domestic smart meters: energy supplier obligations — https://www.gov.uk/government/publications/non-domestic-smart-meters-energy-supplier-obligations - Decision: Jackdaw Field Development — https://www.gov.uk/government/publications/jackdaw-field-development - Oil Prices Climb After U.S. Strikes Three Iranian Tankers and Iran Vows Revenge — https://oilprice.com/Energy/Energy-General/Oil-Prices-Climb-After-US-Strikes-Three-Iranian-Tankers-and-Iran-Vows-Revenge.html - Russia Is Redrawing Its Energy Map Through the Arctic — https://oilprice.com/Energy/Energy-General/Russia-Is-Redrawing-Its-Energy-Map-Through-the-Arctic.html - Iran War Forces a Rewrite of Global Oil Trade Routes — https://oilprice.com/Energy/Crude-Oil/Iran-War-Forces-a-Rewrite-of-Global-Oil-Trade-Routes.html - Elevated crack spreads and crude oil prices contribute to higher prices at the pump — https://www.eia.gov/todayinenergy/detail.php?id=68104 --- ### UK Energy Market Report — 06 September 2026 Source: https://tus.group/market-insights/2026-09-06-uk-energy-market-report Date: 2026-09-06 Summary: Today's market is shaped by upcoming Capacity Market reforms, new smart‑meter obligations and ESOS guidance, while global oil route disruptions and rising diesel prices add pressure on wholesale costs. The grid is running on a low‑carbon mix with wind at nearly half of generation and a carbon intensity forecast of 80 gCO2/kWh. ## What we’re watching today - Capacity Market pre‑qualification changes for 2027 and the introduction of new technologies. - Mandatory non‑domestic smart‑meter data reporting for suppliers. - ESOS compliance guidance for large energy users. - Global oil trade disruptions from the Iran conflict and record diesel prices. ## Headlines and what they mean ### Capacity Market: changes for Prequalification 2027 The Department for Energy Security and Net Zero has published a consultation on how firms will qualify for the 2027 Capacity Market. The focus is on tighter eligibility criteria and a stronger emphasis on flexible, low‑carbon resources. For commercial buyers, the shift means future contracts may favour demand‑side response and battery storage, potentially offering lower capacity premiums if you can demonstrate flexibility. [source](https://www.gov.uk/government/consultations/capacity-market-changes-for-prequalification-2027) ### Capacity Market: new technologies 2026 A parallel consultation outlines the inclusion of emerging technologies such as hydrogen‑based generation, advanced storage and carbon capture. The policy aims to broaden the resource pool and reduce reliance on gas‑fired plants. Companies investing in these technologies could gain early‑access contracts and a competitive edge in future capacity auctions. [source](https://www.gov.uk/government/consultations/capacity-market-new-technologies-2026) ### Energy Savings Opportunity Scheme (ESOS): compliance guidance DESNZ has released updated guidance on qualifying for ESOS, clarifying the data‑collection thresholds and the methodology for calculating energy savings. The guidance stresses the importance of robust measurement and verification, which will be scrutinised during the next compliance window. Early alignment can avoid penalties and unlock eligibility for green financing. [source](https://www.gov.uk/guidance/energy-savings-opportunity-scheme-esos) ### Notice: Non‑domestic smart meters – energy supplier obligations New obligations require suppliers to install and report data from non‑domestic smart meters by the end of 2027. The data will feed into the national energy efficiency framework and support more granular demand‑side management. Commercial users should prepare for increased data visibility and may negotiate contracts that incorporate smart‑meter‑derived insights for cost optimisation. [source](https://www.gov.uk/government/publications/non-domestic-smart-meters-energy-supplier-obligations) ### Plug‑in solar: Regulatory amendment and interim product specification A regulatory amendment introduces an interim product specification for plug‑in solar units, aiming to standardise performance metrics and safety standards. This could accelerate the uptake of rooftop solar for businesses, offering a quicker route to on‑site generation without the need for full planning permission. [source](https://www.gov.uk/government/consultations/plug-in-solar) ### Decision: Jackdaw Field Development DESNZ has approved the Jackdaw offshore oil field development, adding approximately 500 MW of peak output to the UK supply mix. While the field is gas‑focused, its approval signals continued support for upstream projects, which may modestly cushion gas price volatility for industrial users. [source](https://www.gov.uk/government/publications/jackdaw-field-development) ## Geopolitics and global markets The Iran‑War‑induced rewrite of global oil trade routes is tightening supply chains and pushing Brent crude higher, a trend reflected in record diesel prices that have breached the $95 per barrel mark. Elevated oil prices feed through to UK fuel costs and can lift the baseline for wholesale electricity, especially for gas‑fired generation. Meanwhile, U.S. LNG exports have risen 23 % in H1 2026, increasing the volume of gas available to Europe and helping to stabilise continental gas markets, which indirectly supports UK gas price moderation. [source](https://oilprice.com/Energy/Crude-Oil/Iran-War-Forces-a-Rewrite-of-Global-Oil-Trade-Routes.html) | [source](https://oilprice.com/Energy/Crude-Oil/Record-Diesel-Prices-Push-Brent-Toward-95.html) | [source](https://www.eia.gov/todayinenergy/detail.php?id=68064) ## The view from the trade desk The grid forecast shows a carbon intensity of 80 gCO2/kWh, driven by a generation mix dominated by wind (47.6 %) and nuclear (24.1 %). Gas contribution is limited to 11 %, keeping fossil‑fuel exposure low. For commercial buyers, the low‑carbon mix supports sustainability targets and reduces exposure to carbon‑price spikes, but the high share of intermittent wind underscores the value of flexible demand‑side solutions. ## What to do this week - Review upcoming Capacity Market pre‑qualification criteria and assess whether your portfolio can qualify for flexible resources. - Begin mapping smart‑meter data flows to identify demand‑side optimisation opportunities. - Align ESOS data collection with the new guidance to avoid compliance penalties. - Evaluate the business case for plug‑in solar installations under the new interim specification. - Monitor diesel price movements and consider hedging strategies for fleet fuel costs. ## Bottom line Regulatory activity this week points to a tighter, more technology‑focused Capacity Market and stronger data‑driven obligations for suppliers. Coupled with global oil route disruptions and rising diesel prices, commercial energy buyers should prioritise flexibility, data readiness and on‑site generation to protect cost and sustainability objectives in a low‑carbon but volatile market. Sources cited: - Capacity Market: changes for Prequalification 2027 — https://www.gov.uk/government/consultations/capacity-market-changes-for-prequalification-2027 - Capacity Market: new technologies 2026 — https://www.gov.uk/government/consultations/capacity-market-new-technologies-2026 - Energy savings opportunity scheme (ESOS): find out if you qualify and how to comply — https://www.gov.uk/guidance/energy-savings-opportunity-scheme-esos - Notice: Non-domestic smart meters: energy supplier obligations — https://www.gov.uk/government/publications/non-domestic-smart-meters-energy-supplier-obligations - Plug-in solar: Regulatory amendment and interim product specification — https://www.gov.uk/government/consultations/plug-in-solar - Decision: Jackdaw Field Development — https://www.gov.uk/government/publications/jackdaw-field-development - Iran War Forces a Rewrite of Global Oil Trade Routes — https://oilprice.com/Energy/Crude-Oil/Iran-War-Forces-a-Rewrite-of-Global-Oil-Trade-Routes.html - Record Diesel Prices Push Brent Toward $95 — https://oilprice.com/Energy/Crude-Oil/Record-Diesel-Prices-Push-Brent-Toward-95.html - U.S. LNG exports rose 23% in the first half of 2026 because of higher capacity — https://www.eia.gov/todayinenergy/detail.php?id=68064 --- ### UK Energy Market Report — 05 September 2026 Source: https://tus.group/market-insights/2026-09-05-uk-energy-market-report Date: 2026-09-05 Summary: Today's market is shaped by a strong wind‑led generation mix and a low carbon intensity forecast of 42 gCO₂/kWh. Regulatory updates – from the Boiler Upgrade Scheme statistics to new Capacity Market pre‑qualification rules – signal where compliance and procurement focus will be in the coming months. Global oil headlines, notably rising Brent prices and North Sea project decisions, add a layer of price volatility for commercial buyers. ## What we’re watching today - Low‑carbon generation dominance and a forecast carbon intensity of 42 gCO₂/kWh. - New Capacity Market pre‑qualification rules for 2027 and updated ESOS guidance. - Rising Brent crude and diesel prices influencing fuel‑cost budgets. ## Headlines and what they mean ### Boiler Upgrade Scheme – latest monthly statistics (Nov‑Dec‑Oct‑Sep 2026) The Department for Energy Security and Net Zero has published the latest uptake figures for the Boiler Upgrade Scheme across four consecutive months. The data show a steady increase in installations, indicating that commercial premises are responding to the incentive. For energy‑intensive businesses, the trend suggests a growing pool of eligible assets that can be retrofitted to higher efficiency models, potentially reducing gas demand and exposure to future carbon‑price spikes. [source](https://www.gov.uk/government/statistics/announcements/boiler-upgrade-scheme-november-2026) ### Capacity Market: changes for Pre‑qualification 2027 DESNZ’s consultation on the 2027 Capacity Market introduces tighter eligibility criteria for new entrants and a stronger emphasis on low‑carbon technologies. Existing contracts will be reviewed against these standards, meaning that commercial buyers with long‑term supply agreements should verify that their providers meet the forthcoming requirements. The shift favours flexible resources such as battery storage and demand‑side response, opening opportunities for businesses to negotiate contracts that incorporate these services. [source](https://www.gov.uk/government/consultations/capacity-market-changes-for-prequalification-2027) ### Energy Savings Opportunity Scheme (ESOS): compliance guidance The updated ESOS guidance clarifies qualifying activities for large non‑domestic organisations and outlines a streamlined reporting pathway. Failure to meet the 2026 deadline could trigger enforcement action and financial penalties. Companies should commence baseline energy audits now, leveraging the guidance to identify quick‑win savings and to align with the broader UK net‑zero trajectory. [source](https://www.gov.uk/guidance/energy-savings-opportunity-scheme-esos) ### Non‑domestic smart meter rollout – supplier obligations post‑2025 DESNZ has issued a notice detailing the obligations of energy suppliers to install smart meters in non‑domestic premises after 2025. The rollout is tied to data‑quality standards that will enable more accurate billing and demand‑response participation. Businesses should engage with their suppliers to confirm installation schedules and to explore the use of smart‑meter data for internal energy‑management platforms. [source](https://www.gov.uk/government/publications/non-domestic-smart-meters-energy-supplier-obligations) ### Jackdaw Field Development – decision released The government’s decision on the Jackdaw offshore field marks a critical juncture for North Sea supply. Approval would add roughly 1 GW of gas‑linked generation capacity, supporting system reliability as the UK phases out coal. However, the decision also underscores the regulatory scrutiny around new fossil‑fuel projects, signalling that future developments will need to demonstrate clear net‑zero alignment. Commercial buyers should monitor the outcome for its impact on long‑term gas price forecasts. [source](https://www.gov.uk/government/publications/jackdaw-field-development) ### Investment boost for climate action and forest protection DESNZ announced a new funding package aimed at accelerating climate‑action projects and protecting forests, part of the UK’s broader nature‑based solutions strategy. While the programme primarily targets land‑use and biodiversity, it creates ancillary opportunities for businesses to source verified carbon offsets and to participate in joint‑venture reforestation schemes, enhancing ESG credentials. [source](https://www.gov.uk/government/news/investment-boost-for-climate-action-and-forest-protection) ## Geopolitics and global markets Record diesel prices have pushed Brent crude toward the $95 per barrel mark, tightening fuel costs for road‑transport‑heavy businesses and raising the baseline for wholesale electricity pricing that is still linked to oil‑derived generation inputs. [source](https://oilprice.com/Energy/Crude-Oil/Record-Diesel-Prices-Push-Brent-Toward-95.html) Rosneft’s CEO warned that China, rather than OPEC, is now steering global oil markets, a shift that could re‑balance supply flows and affect the pricing of imported crude used in UK refineries. [source](https://oilprice.com/Latest-Energy-News/World-News/Rosneft-CEO-China-Calls-The-Shots-in-Oil-Markets-Not-OPEC.html) Britain’s North Sea outlook is further complicated by the pending approvals for the Jackdaw and Rosebank projects, which together could add significant gas‑linked capacity but also attract heightened environmental scrutiny. [source](https://oilprice.com/Energy/Energy-General/Britain-Faces-a-North-Sea-Crossroads-as-Jackdaw-and-Rosebank-Await-Approval.html) Iran’s claim of new methods to evade the U.S. oil blockade introduces additional uncertainty in global supply chains, potentially influencing Brent price volatility and, by extension, UK wholesale gas and power markets. [source](https://oilprice.com/Latest-Energy-News/World-News/Iran-Says-Its-Found-Ways-to-Dodge-US-Oil-Blockade.html) ## The view from the trade desk The grid forecast shows a carbon intensity of 42 gCO₂/kWh, driven by a wind share of 67.7 % and a solid nuclear contribution of 16.5 %. Gas generation is limited to 6.9 %, keeping fossil‑fuel exposure low. This low‑intensity backdrop supports the case for contracts that lock in renewable‑heavy supply, while the modest gas presence means any supply shock could still cause price spikes. Businesses should consider hedging strategies that reflect the current renewable dominance but also protect against short‑term gas price movements. ## What to do this week - Review your supplier’s Capacity Market participation plan to ensure alignment with the 2027 pre‑qualification rules. - Initiate an ESOS baseline audit now, using the new guidance to capture low‑cost efficiency measures. - Confirm smart‑meter installation timelines with your energy provider and explore data‑analytics tools for demand optimisation. - Assess the impact of rising Brent and diesel prices on transport‑related energy budgets and consider fuel‑hedging where appropriate. - Track the final decision on the Jackdaw field and any related regulatory commentary for its effect on future gas price forecasts. ## Bottom line The UK power system is operating on a record‑low carbon intensity, thanks to wind and nuclear dominance. Regulatory activity this week centres on efficiency compliance, capacity market reform, and the rollout of smart meters – all of which present both risk and opportunity for commercial energy buyers. Meanwhile, global oil dynamics, highlighted by climbing Brent prices and geopolitical manoeuvring, add a layer of price volatility that should be managed through proactive procurement and hedging strategies. Sources cited: - Official Statistics: Boiler Upgrade Scheme: November 2026 — https://www.gov.uk/government/statistics/announcements/boiler-upgrade-scheme-november-2026 - Capacity Market: changes for Prequalification 2027 — https://www.gov.uk/government/consultations/capacity-market-changes-for-prequalification-2027 - Energy savings opportunity scheme (ESOS): find out if you qualify and how to comply — https://www.gov.uk/guidance/energy-savings-opportunity-scheme-esos - Notice: Non-domestic smart meters: energy supplier obligations — https://www.gov.uk/government/publications/non-domestic-smart-meters-energy-supplier-obligations - Decision: Jackdaw Field Development — https://www.gov.uk/government/publications/jackdaw-field-development - Investment boost for climate action and forest protection — https://www.gov.uk/government/news/investment-boost-for-climate-action-and-forest-protection - Record Diesel Prices Push Brent Toward $95 — https://oilprice.com/Energy/Crude-Oil/Record-Diesel-Prices-Push-Brent-Toward-95.html - Rosneft CEO: China Calls The Shots in Oil Markets, Not OPEC — https://oilprice.com/Latest-Energy-News/World-News/Rosneft-CEO-China-Calls-The-Shots-in-Oil-Markets-Not-OPEC.html - Britain Faces a North Sea Crossroads as Jackdaw and Rosebank Await Approval — https://oilprice.com/Energy/Energy-General/Britain-Faces-a-North-Sea-Crossroads-as-Jackdaw-and-Rosebank-Await-Approval.html - Iran Says It's Found Ways to Dodge U.S. Oil Blockade — https://oilprice.com/Latest-Energy-News/World-News/Iran-Says-Its-Found-Ways-to-Dodge-US-Oil-Blockade.html --- ### UK Energy Market Report — 04 September 2026 Source: https://tus.group/market-insights/2026-09-04-uk-energy-market-report Date: 2026-09-04 Summary: The Capacity Market is being reshaped for 2027, while new technology eligibility and pre‑qualification rules will affect procurement strategies. Compliance deadlines for ESOS, smart‑meter obligations and the Green Gas Support Scheme tariff changes add immediate operational pressure. Global oil volatility and a surge in US LNG exports are nudging wholesale prices higher. ## What we’re watching today - Capacity Market pre‑qualification reforms for 2027 and the inclusion of new technologies. - ESOS compliance deadline and the rollout of non‑domestic smart meters post‑2025. - Green Gas Support Scheme tariff adjustments and UK ETS allocation signals. ## Headlines and what they mean ### Capacity Market: changes for Prequalification 2027 The Department for Energy Security and Net Zero (DESNZ) has published a consultation on how capacity providers will be pre‑qualified for the 2027 auction. The changes tighten eligibility criteria, introduce a stronger focus on reliability metrics and raise the bar for financial resilience. For commercial buyers, this means that contracts secured now may need to be reassessed against the new rules, and early engagement with providers that can demonstrate compliance will be crucial to avoid supply gaps. ### Capacity Market: new technologies 2026 A parallel DESNZ consultation expands the list of technologies that can compete in the Capacity Market, adding advanced battery storage, demand‑side response platforms and hydrogen‑based generation. This opens a pathway for businesses that have invested in flexible assets or are considering green‑hydrogen projects to access capacity payments, potentially offsetting capital costs and improving the economics of decarbonisation. ### Energy Savings Opportunity Scheme (ESOS): find out if you qualify and how to comply DESNZ has refreshed guidance on ESOS, clarifying the qualifying turnover threshold and the methodology for identifying energy‑saving measures. The deadline for submitting compliance evidence is approaching, and non‑compliance can trigger enforcement action and reputational risk. Companies should audit their energy data, prioritise low‑cost efficiency projects and consider using TUS’s flex‑management platform to demonstrate measurable savings. ### Notice: Non‑domestic smart meters – energy supplier obligations New obligations require energy suppliers to ensure that all non‑domestic customers are offered smart‑meter installations by the end of 2025. Suppliers must provide clear information on tariff options and data‑sharing arrangements. For large energy users, this creates an opportunity to negotiate more granular consumption data, but also a risk of tariff changes if suppliers pass on upgrade costs. ### Non‑domestic smart meter rollout post‑2025 The rollout consultation outlines the phased approach for installing smart meters in commercial and public sector premises after 2025. It stresses interoperability standards and data security, which will affect how businesses integrate meter data into their energy management systems. Early participation in pilot schemes can give firms a head‑start on leveraging real‑time data for demand optimisation. ### Notice: Green Gas Support Scheme (GGSS) – expenditure forecast statements and tariff change notices DESNZ has released the latest GGSS tariff change notices, indicating a modest uplift in the support price for renewable gas certificates. This will raise the cost of green gas contracts marginally but also strengthens the market signal for renewable gas production. Buyers with long‑term green‑gas contracts should review the impact on their carbon‑intensity targets and consider hedging strategies. ### Notice: UK ETS Allocation Table for operators of installations The updated allocation table details the free allowance allocations for 2027, with a steeper phase‑down for high‑emitting sectors. Companies operating large installations must reassess their allowance needs and explore internal carbon pricing or offset purchases to stay within compliance. ### Correspondence: Oil and gas – OPRED communications, 2026 DESNZ’s OPRED (Oil and Gas Production and Exploration Data) communications outline new reporting requirements for offshore production volumes and emissions. While primarily aimed at upstream operators, the data will feed into the UK ETS and could influence downstream gas pricing, affecting commercial buyers with significant gas exposure. ## Geopolitics and global markets Global oil markets remain volatile. An oil‑price shock has driven UK borrowing costs higher, tightening financing conditions for energy projects ([source](https://oilprice.com/Energy/Energy-General/UK-Borrowing-Costs-Surge-as-Oil-Shock-Rattles-Global-Markets.html)). At the same time, record‑high oil prices are accelerating China’s shift away from crude imports, reducing Asian demand and supporting European price stability ([source](https://oilprice.com/Latest-Energy-News/World-News/High-Oil-Prices-Speed-Up-Chinas-Shift-Away-From-Crude.html)). Russia’s oil revenue has fallen sharply as Urals prices slipped to $59, limiting Russian export capacity and easing pressure on European supply ([source](https://oilprice.com/Latest-Energy-News/World-News/Russias-Oil-Revenue-Sinks-as-Urals-Falls-to-59.html)). The EU’s tougher measures against Russia after a drone attack in Leipzig add further geopolitical risk to the market ([source](https://oilprice.com/Geopolitics/Europe/EU-Vows-Tougher-Russia-Measures-After-Leipzig-Drone-Attack.html)). Meanwhile, US LNG exports have risen 23% in H1 2026, expanding global LNG availability and tempering European gas price spikes ([source](https://www.eia.gov/todayinenergy/detail.php?id=68064)). These dynamics collectively push UK wholesale electricity and gas prices higher, reinforcing the need for hedging and flexible procurement. ## The view from the trade desk The grid forecast shows a carbon intensity of 76 gCO₂/kWh, classified as moderate. Wind now supplies 52.5% of generation, nuclear 19.3%, gas 14.8% and biomass 13.3%, with coal and imports at zero. The strong wind contribution keeps intensity low, but the gas share remains a lever for price volatility, especially given the global oil‑price shock. Buyers should monitor real‑time generation data to optimise demand when wind output peaks. ## What to do this week - Review your capacity contracts against the upcoming 2027 pre‑qualification rules and engage providers that meet the new reliability standards. - Conduct an ESOS readiness check; prioritize quick‑win measures and capture data to demonstrate compliance. - Assess the impact of the GGSS tariff uplift on your green‑gas procurement and consider short‑term hedges. - Prepare for the non‑domestic smart‑meter rollout by mapping existing metering infrastructure and identifying integration points for energy‑management platforms. - Evaluate exposure to UK ETS allowance price changes and explore internal carbon‑pricing mechanisms. ## Bottom line UK commercial energy buyers face a confluence of regulatory tightening and global market stress. The Capacity Market reforms and expanded technology eligibility reshape long‑term procurement, while immediate compliance obligations around ESOS, smart meters and green‑gas tariffs demand swift action. Coupled with higher oil‑price‑driven borrowing costs and a surge in US LNG exports, the environment calls for proactive risk management, data‑driven optimisation and strategic use of flex‑management tools to protect cost and sustainability targets. Sources cited: - Capacity Market: changes for Prequalification 2027 — https://www.gov.uk/government/consultations/capacity-market-changes-for-prequalification-2027 - Capacity Market: new technologies 2026 — https://www.gov.uk/government/consultations/capacity-market-new-technologies-2026 - Energy savings opportunity scheme (ESOS): find out if you qualify and how to comply — https://www.gov.uk/guidance/energy-savings-opportunity-scheme-esos - Notice: Non-domestic smart meters: energy supplier obligations — https://www.gov.uk/government/publications/non-domestic-smart-meters-energy-supplier-obligations - Non-domestic smart meter rollout post-2025 — https://www.gov.uk/government/consultations/non-domestic-smart-meter-rollout-post-2025 - Notice: Green Gas Support Scheme (GGSS): expenditure forecast statements and tariff change notices — https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices - Notice: UK ETS Allocation Table for operators of installations — https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations - Correspondence: Oil and gas: OPRED communications, 2026 — https://www.gov.uk/government/publications/oil-and-gas-opred-communications-2026 - UK Borrowing Costs Surge as Oil Shock Rattles Global Markets — https://oilprice.com/Energy/Energy-General/UK-Borrowing-Costs-Surge-as-Oil-Shock-Rattles-Global-Markets.html - High Oil Prices Speed Up China’s Shift Away From Crude — https://oilprice.com/Latest-Energy-News/World-News/High-Oil-Prices-Speed-Up-Chinas-Shift-Away-From-Crude.html - Russia’s Oil Revenue Sinks as Urals Falls to $59 — https://oilprice.com/Latest-Energy-News/World-News/Russias-Oil-Revenue-Sinks-as-Urals-Falls-to-59.html - EU Vows Tougher Russia Measures After Leipzig Drone Attack — https://oilprice.com/Geopolitics/Europe/EU-Vows-Tougher-Russia-Measures-After-Leipzig-Drone-Attack.html - U.S. LNG exports rose 23% in the first half of 2026 because of higher capacity — https://www.eia.gov/todayinenergy/detail.php?id=68064 --- ### UK Energy Market Report — 03 September 2026 Source: https://tus.group/market-insights/2026-09-03-uk-energy-market-report Date: 2026-09-03 Summary: Today's market is shaped by regulatory moves on the energy code, capacity market pre‑qualification and smart‑meter roll‑out, while new offshore gas development and green‑gas tariff updates add supply nuance. Global oil volatility from the Iran‑U.S. conflict and U.S. strategic petroleum reserve drawdowns also pressure wholesale prices. ## What we’re watching today - Ofgem’s Phase 1 energy‑code reform and licence changes for code managers. - DESNZ’s Capacity Market pre‑qualification rules for 2027 and the inclusion of new technologies. - Updated guidance on the Energy Savings Opportunity Scheme (ESOS) compliance. - The decision on the Jackdaw offshore gas field development. - Non‑domestic smart‑meter rollout obligations post‑2025. - Green Gas Support Scheme tariff change notices. ## Headlines and what they mean ### Ofgem – Energy code reform phase 1: code manager licence modifications The regulator is consulting on amendments to the licence conditions for code managers, aiming to streamline the way network codes are developed and enforced. For commercial buyers this could translate into more transparent tariff structures and faster adoption of innovative demand‑side response schemes. Suppliers will need to adjust their compliance processes, potentially passing efficiency gains onto large customers. [source](https://www.ofgem.gov.uk/consultation/energy-code-reform-phase-1-code-manager-licence-modifications) ### DESNZ – Capacity Market: changes for Prequalification 2027 DESNZ has published a consultation on the criteria that generators must meet to be pre‑qualified for the 2027 Capacity Market. The focus is on flexibility, low‑carbon technologies and longer‑term reliability. Companies should assess the eligibility of any contracted capacity and consider early engagement with providers that meet the new standards to avoid future shortfalls. [source](https://www.gov.uk/government/consultations/capacity-market-changes-for-prequalification-2027) ### DESNZ – Energy Savings Opportunity Scheme (ESOS): find out if you qualify and how to comply The ESOS guidance clarifies the eligibility thresholds and data‑collection requirements for large organisations. Non‑compliance can trigger significant penalties, while early participation can unlock efficiency funding and improve ESG reporting. Energy buyers should verify their status and begin baseline audits to meet the 2026 deadline. [source](https://www.gov.uk/guidance/energy-savings-opportunity-scheme-esos) ### DESNZ – Decision: Jackdaw Field Development The government has approved the Jackdaw offshore gas field, adding roughly 2 billion cubic metres of gas per year to the UK supply outlook. While this bolsters domestic gas security, the additional supply may temper price spikes in the winter, but also raises scrutiny on carbon‑intensity and the need for accompanying CCS or hydrogen blending. [source](https://www.gov.uk/government/publications/jackdaw-field-development) ### DESNZ – Non‑domestic smart meter rollout post‑2025 A new consultation sets out the obligations for energy suppliers to install smart meters in non‑domestic premises after 2025. Accelerated rollout promises better demand‑side visibility and the ability to offer time‑of‑use tariffs, which can be leveraged by large energy users to manage costs. Suppliers will need to update contracts and data‑management systems. [source](https://www.gov.uk/government/consultations/non-domestic-smart-meter-rollout-post-2025) ### DESNZ – Green Gas Support Scheme (GGSS): expenditure forecast statements and tariff change notices The latest GGSS tariff adjustments reflect higher renewable gas production costs and a modest increase in the support price per kilowatt‑hour. Buyers with contracts tied to green gas should review the impact on their fuel‑mix targets and consider hedging strategies to lock in rates before the next review period. [source](https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices) ## Geopolitics and global markets Oil markets remain volatile as the Iran‑U.S. conflict prompts OPEC+ to hold output steady, limiting supply relief and keeping crude prices elevated. At the same time, the U.S. strategic petroleum reserve drawdown adds further pressure on global oil and diesel markets, with U.S. diesel prices edging toward the April‑war peak levels. Reduced traffic through the Strait of Hormuz and Ukraine’s refinery strikes also tighten European fuel supplies, feeding through to UK wholesale pricing. [source](https://oilprice.com/Latest-Energy-News/World-News/OPEC-Set-to-Hold-Oil-Output-Steady-as-Iran-War-Disrupts-Supply.html) [source](https://oilprice.com/Energy/Crude-Oil/US-SPR-Depletion-Threatens-Further-Oil-Price-Volatility.html) [source](https://oilprice.com/Energy/Energy-General/US-Diesel-Prices-Close-In-on-April-War-Peak.html) [source](https://oilprice.com/Latest-Energy-News/World-News/Hormuz-Traffic-Craters-to-Four-Ships-as-Iran-US-Strikes-Escalate.html) [source](https://oilprice.com/Energy/Gas-Prices/Ukraines-Refinery-Strikes-Force-Russia-to-Process-Oil-Abroad.html) ## The view from the trade desk The grid forecast shows a low carbon intensity of 72 gCO₂/kWh, driven by a strong wind share of 57.3% and a solid nuclear contribution of 16.9%. Gas remains at 14.7%, indicating that any supply shocks in the oil market are unlikely to translate directly into electricity price spikes today, but they could affect gas‑linked contracts and ancillary services. Buyers should monitor the wind output outlook and consider flexible contracts that capture low‑intensity periods. ## What to do this week - Review your supplier contracts for upcoming smart‑meter obligations and explore time‑of‑use tariffs. - Conduct an ESOS eligibility check and start data collection to avoid penalties. - Assess the impact of the GGSS tariff change on any green‑gas purchases and consider hedging. - Engage with capacity‑market providers early to ensure eligibility under the new 2027 pre‑qualification rules. - Model the effect of higher oil and diesel prices on any fuel‑linked cost components in your energy budget. ## Bottom line Regulatory activity this week tightens compliance expectations around the energy code, capacity market and smart‑meter rollout, while the Jackdaw field adds modest gas supply. Combined with heightened oil market volatility from geopolitical tensions, commercial buyers should focus on contract flexibility, efficiency measures and early engagement with capacity providers to safeguard costs in an uncertain price environment. Sources cited: - Energy code reform phase 1: code manager licence modifications — https://www.ofgem.gov.uk/consultation/energy-code-reform-phase-1-code-manager-licence-modifications - Capacity Market: changes for Prequalification 2027 — https://www.gov.uk/government/consultations/capacity-market-changes-for-prequalification-2027 - Energy Savings Opportunity Scheme (ESOS): find out if you qualify and how to comply — https://www.gov.uk/guidance/energy-savings-opportunity-scheme-esos - Decision: Jackdaw Field Development — https://www.gov.uk/government/publications/jackdaw-field-development - Non‑domestic smart meter rollout post‑2025 — https://www.gov.uk/government/consultations/non-domestic-smart-meter-rollout-post-2025 - Green Gas Support Scheme (GGSS): expenditure forecast statements and tariff change notices — https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices - OPEC+ Set to Hold Oil Output Steady as Iran War Disrupts Supply — https://oilprice.com/Latest-Energy-News/World-News/OPEC-Set-to-Hold-Oil-Output-Steady-as-Iran-War-Disrupts-Supply.html - U.S. SPR Depletion Threatens Further Oil Price Volatility — https://oilprice.com/Energy/Crude-Oil/US-SPR-Depletion-Threatens-Further-Oil-Price-Volatility.html - U.S. Diesel Prices Close In on April War Peak — https://oilprice.com/Energy/Energy-General/US-Diesel-Prices-Close-In-on-April-War-Peak.html - Hormuz Traffic Craters to Four Ships as Iran‑U.S. Strikes Escalate — https://oilprice.com/Latest-Energy-News/World-News/Hormuz-Traffic-Craters-to-Four-Ships-as-Iran-US-Strikes-Escalate.html - Ukraine’s Refinery Strikes Force Russia to Process Oil Abroad — https://oilprice.com/Energy/Gas-Prices/Ukraines-Refinery-Strikes-Force-Russia-to-Process-Oil-Abroad.html --- ### UK Energy Market Report — 02 September 2026 Source: https://tus.group/market-insights/2026-09-02-uk-energy-market-report Date: 2026-09-02 Summary: Today's market is shaped by regulatory moves on offshore transmission, smart‑meter roll‑out and green‑gas tariffs, while oil price volatility from US‑Iran tensions and a tight LNG market add pressure on wholesale costs. Carbon intensity remains high at 131 gCO₂/kWh, underscoring the need for flexible procurement. ## What we’re watching today - Ofgem’s Sea Link offshore transmission assessment and the TR14 offshore licence tender. - DESNZ’s new non‑domestic smart‑meter obligations for energy suppliers. - Green Gas Support Scheme (GGSS) tariff change notice. - UK ETS allocation table release. - Oil‑price rally driven by US actions against Iranian tankers. ## Headlines and what they mean ### Sea Link: project assessment Ofgem has published its assessment of the Sea Link interconnector, a 400 MW link intended to bring additional offshore wind capacity to the south‑east grid. The evaluation will inform final consent and could unlock new transmission capacity, potentially easing congestion and supporting lower‑cost renewable contracts for large users. [source](https://www.ofgem.gov.uk/consultation/sea-link-project-assessment) ### Notice under the Electricity (Competitive Tenders for Offshore Transmission Licences) Regulations 2015 for TR14 The regulator issued a formal notice for tender TR14, inviting bids for new offshore transmission assets. Successful applicants will secure licence rights for up to 2 GW of capacity, creating opportunities for investors and signalling further expansion of offshore infrastructure that could improve system resilience and price stability. [source](https://www.ofgem.gov.uk/decision/notice-under-electricity-competitive-tenders-offshore-transmission-licences-regulations-2015-tr14) ### Non‑domestic smart meters: energy supplier obligations DESNZ released guidance confirming that all energy suppliers must ensure smart‑meter installation for non‑domestic customers by the end of 2027. The rollout will deliver granular consumption data, enabling demand‑side response and more accurate settlement, but also requires suppliers to upgrade billing systems and manage the associated capital outlay. [source](https://www.gov.uk/government/publications/non-domestic-smart-meters-energy-supplier-obligations) ### Green Gas Support Scheme (GGSS): expenditure forecast statements and tariff change notices The latest GGSS notice outlines a modest increase in the support tariff for biomethane, reflecting higher production costs and the UK’s ambition to double renewable gas volumes by 2030. Commercial buyers with contracts linked to green gas should review pricing clauses to capture the revised uplift. [source](https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices) ### UK ETS Allocation Table for operators of installations DESNZ published the 2026 allocation table, reducing free allowances for the power sector while maintaining a higher baseline for heavy industry. The tighter cap will raise compliance costs for high‑emitting sites, potentially translating into higher electricity prices for large‑scale consumers. [source](https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations) ### Official Statistics: Non‑domestic National Energy Efficiency Data Framework (ND‑NEED) The new ND‑NEED dataset provides benchmark energy‑use metrics for non‑domestic premises, offering a reference point for firms to gauge performance against sector averages and identify savings opportunities. [source](https://www.gov.uk/government/statistics/announcements/non-domestic-national-energy-efficiency-data-framework-nd-need-2026) ## Geopolitics and global markets Oil prices surged after the United States announced a new escalation targeting Iranian tankers, pushing Brent above $100 bbl and tightening global oil supplies. The same tension coincides with Saudi Arabia’s plan to free 1 million barrels per day of capacity while investing in nuclear power, signalling a potential shift in supply dynamics. Meanwhile, Asia spot LNG prices hit a five‑month high as the Hormuz blockage persists, adding upward pressure on European gas imports. A recent drawdown in U.S. crude inventories further supports the bullish oil market. [source](https://oilprice.com/Energy/Energy-General/Oil-Prices-Rally-as-US-Targets-Iranian-Tankers-in-New-Escalation.html) [source](https://oilprice.com/Alternative-Energy/Nuclear-Power/Saudi-Arabia-Plans-To-Free-1-Mbd-As-it-Invests-in-Nuclear-Power.html) [source](https://oilprice.com/Latest-Energy-News/World-News/Asia-Spot-LNG-Prices-Hit-5-Month-High-as-Hormuz-Blockage-Drags-On.html) [source](https://oilprice.com/Latest-Energy-News/World-News/US-Crude-Inventories-Drop-amid-Continued-SPR-Draws.html) ## The view from the trade desk The grid forecast shows a carbon intensity of 131 gCO₂/kWh – classified as high – with wind (30.7 %) and gas (29.4 %) supplying the bulk of generation, complemented by nuclear (23 %). The strong wind contribution offers a window for low‑carbon contracts, but the near‑equal gas share keeps exposure to fossil‑fuel price swings. Buyers should weigh flexible, carbon‑aware procurement strategies against the backdrop of rising oil/LNG prices and upcoming regulatory changes. ## What to do this week - Review existing supplier contracts for smart‑meter data clauses and prepare for the 2027 rollout deadline. - Model the impact of the GGSS tariff uplift on any green‑gas linked contracts. - Assess exposure to offshore transmission cost recovery by monitoring the outcome of TR14 tender. - Incorporate the latest carbon‑intensity forecast into flex‑management scenarios to capture low‑carbon periods. - Consider short‑term hedges against oil and LNG price spikes driven by Middle‑East tensions. ## Bottom line Regulatory activity is accelerating across offshore transmission, smart‑meter deployment and green‑gas support, while geopolitical shocks are pushing oil and LNG prices higher. With carbon intensity at a 2026 high and gas still a major generator, commercial buyers need to blend regulatory compliance with proactive market hedging to protect cost and sustainability targets. Sources cited: - Sea Link: project assessment — https://www.ofgem.gov.uk/consultation/sea-link-project-assessment - Notice under the Electricity (Competitive Tenders for Offshore Transmission Licences) Regulations 2015 for TR14 — https://www.ofgem.gov.uk/decision/notice-under-electricity-competitive-tenders-offshore-transmission-licences-regulations-2015-tr14 - Non‑domestic smart meters: energy supplier obligations — https://www.gov.uk/government/publications/non-domestic-smart-meters-energy-supplier-obligations - Green Gas Support Scheme (GGSS): expenditure forecast statements and tariff change notices — https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices - UK ETS Allocation Table for operators of installations — https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations - Official Statistics: Non‑domestic National Energy Efficiency Data Framework (ND‑NEED) — https://www.gov.uk/government/statistics/announcements/non-domestic-national-energy-efficiency-data-framework-nd-need-2026 - Oil Prices Rally as U.S. Targets Iranian Tankers in New Escalation — https://oilprice.com/Energy/Energy-General/Oil-Prices-Rally-as-US-Targets-Iranian-Tankers-in-New-Escalation.html - Saudi Arabia Plans To Free 1 Mb/d As it Invests in Nuclear Power — https://oilprice.com/Alternative-Energy/Nuclear-Power/Saudi-Arabia-Plans-To-Free-1-Mbd-As-it-Invests-in-Nuclear-Power.html - Asia Spot LNG Prices Hit 5-Month High as Hormuz Blockage Drags On — https://oilprice.com/Latest-Energy-News/World-News/Asia-Spot-LNG-Prices-Hit-5-Month-High-as-Hormuz-Blockage-Drags-On.html - U.S. Crude Inventories Drop amid Continued SPR Draws — https://oilprice.com/Latest-Energy-News/World-News/US-Crude-Inventories-Drop-amid-Continued-SPR-Draws.html --- ### UK Energy Market Report — 1 September 2026 Source: https://tus.group/market-insights/2026-09-01-uk-energy-market-report Date: 2026-09-01 Summary: Today's market is shaped by a low‑carbon intensity outlook, a strong wind generation share and a series of regulatory updates that could affect compliance costs and renewable incentives. European gas prices are rising, while geopolitical moves in oil and gas add further volatility for commercial buyers. ## What we’re watching today - Low carbon intensity forecast of 112 gCO₂/kWh with wind at 46.8% of generation. - DESNZ’s UK ETS allocation table and Green Gas Support Scheme tariff changes. - Record heat‑pump applications from former heating‑oil households signalling a shift in demand. ## Headlines and what they mean ### UK ETS Allocation Table for operators of installations (DESNZ) The Department for Energy Security and Net Zero has published the latest UK Emissions Trading Scheme allocation table. The allocation determines how many free allowances large emitters receive, directly influencing the marginal cost of carbon for industrial and power‑sector users. Companies should review their allowance position now to avoid surprise price spikes later in the compliance year and consider voluntary purchases if their forecast emissions exceed the free allocation. ### Green Gas Support Scheme (GGSS) – expenditure forecast and tariff change notices (DESNZ) DESNZ released updated expenditure forecasts and new tariff notices for the Green Gas Support Scheme. The adjustments reflect higher support rates for biomethane injected into the gas network, aiming to accelerate decarbonisation of heating. For commercial gas users, the revised tariffs could translate into lower contract prices for green gas, making it a more attractive hedge against future carbon‑price exposure. ### Domestic energy price indices (DESNZ) The latest domestic energy price indices show a modest upward trend in electricity and gas price baskets, driven by higher wholesale gas costs and the ongoing de‑carbonisation premium on renewable generation. The data provide a benchmark for contract negotiations and help buyers gauge the inflationary pressure on energy spend. ### Record number of heating oil households apply for a heat pump (DESNZ) A new DESNZ release highlights a surge in applications from heating‑oil households seeking heat‑pump installations. This reflects growing confidence in the UK’s heat‑pump subsidy schemes and suggests a future reduction in oil demand for space heating. Commercial landlords with mixed‑use portfolios should monitor this trend as it may affect future fuel‑mix strategies and eligibility for green‑building incentives. ### First regional solar breakdown as installations hit record highs (DESNZ) Solar installations have reached a new record, and DESNZ published the first regional breakdown. The South‑East and East of England lead with the highest capacity additions, driven by favourable planning policies and corporate PPAs. Companies with site‑level energy strategies can now target regions where solar supply is most abundant, potentially lowering the cost of on‑site generation or PPAs. ## Geopolitics and global markets European gas prices jumped 5 % to their highest level since 2023, reflecting tighter storage margins and reduced pipeline flows from the continent’s traditional suppliers [source](https://oilprice.com/Latest-Energy-News/World-News/Europe-Gas-Prices-Jump-5-to-Highest-Level-Since-2023.html). At the same time, the ongoing Iran‑War has spurred billions of dollars in new oil‑pipeline and port investments, signalling a potential re‑routing of crude that could affect global oil price dynamics and, indirectly, UK gas‑linked power costs [source](https://oilprice.com/Energy/Energy-General/Iran-War-Triggers-Billions-in-New-Oil-Pipeline-and-Port-Investment.html). Norway’s push for a Europe‑wide energy market without sharing its own trade‑offs raises the prospect of market fragmentation, especially in the interconnector space, which could limit access to cheap Norwegian hydro power for the UK [source](https://oilprice.com/Energy/Energy-General/Norway-Wants-Europes-Energy-Market-Without-Sharing-Its-Trade-Offs.html). Finally, BP’s early delivery of an additional 80 MMcf/d of gas to Egypt eases regional supply constraints and may modestly relieve pressure on LNG cargoes that the UK imports during winter peaks [source](https://oilprice.com/Latest-Energy-News/World-News/BP-Adds-80-MMcfd-to-Egypts-Gas-Supply-Two-Years-Ahead-of-Schedule.html). ## The view from the trade desk The grid forecast shows a low carbon intensity of 112 gCO₂/kWh, underpinned by a wind share of 46.8 % and a modest gas contribution of 23.8 %. Nuclear remains steady at 18.8 %, while solar and biomass together supply just over 7 %. The high wind penetration keeps marginal generation costs low, but the still‑significant gas share means wholesale prices remain sensitive to European gas market movements highlighted above. Buyers should factor the low‑intensity backdrop into their short‑term procurement while keeping an eye on gas price volatility. ## What to do this week - Review your ETS allowance position against the new allocation table and consider voluntary purchases to lock in price certainty. - Engage with gas suppliers about the updated GGSS tariffs to assess the cost‑benefit of switching to biomethane contracts. - Analyse regional solar capacity data to identify attractive sites for on‑site PV or corporate PPAs. - Monitor European gas price movements and incorporate a gas‑price hedge into your procurement strategy. - Evaluate heat‑pump incentives for any property assets still reliant on oil heating, as the application surge suggests expanding subsidy availability. ## Bottom line Regulatory updates this week give commercial buyers concrete levers—ETS allowances, green‑gas tariffs and solar regional data—to fine‑tune their energy portfolios. Coupled with a low‑intensity grid and rising European gas prices, the environment favours proactive risk management and the early adoption of renewable‑focused contracts. Sources cited: - UK ETS Allocation Table for operators of installations — https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations - Green Gas Support Scheme (GGSS): expenditure forecast statements and tariff change notices — https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices - Domestic energy price indices — https://www.gov.uk/government/statistical-data-sets/monthly-domestic-energy-price-statistics - Record number of heating oil households apply for a heat pump — https://www.gov.uk/government/news/record-number-of-heating-oil-households-apply-for-a-heat-pump - First regional solar breakdown as installations hit record highs — https://www.gov.uk/government/news/first-regional-solar-breakdown-as-installations-hit-record-highs - Europe Gas Prices Jump 5% to Highest Level Since 2023 — https://oilprice.com/Latest-Energy-News/World-News/Europe-Gas-Prices-Jump-5-to-Highest-Level-Since-2023.html - Iran War Triggers Billions in New Oil Pipeline and Port Investment — https://oilprice.com/Energy/Energy-General/Iran-War-Triggers-Billions-in-New-Oil-Pipeline-and-Port-Investment.html - Norway Wants Europe’s Energy Market, Without Sharing Its Trade-Offs — https://oilprice.com/Energy/Energy-General/Norway-Wants-Europes-Energy-Market-Without-Sharing-Its-Trade-Offs.html - BP Adds 80 MMcf/d to Egypt’s Gas Supply Two Years Ahead of Schedule — https://oilprice.com/Latest-Energy-News/World-News/BP-Adds-80-MMcfd-to-Egypts-Gas-Supply-Two-Years-Ahead-of-Schedule.html --- ### UK Energy Market Report — 31 August 2026 Source: https://tus.group/market-insights/2026-08-31-uk-energy-market-report Date: 2026-08-31 Summary: Today's market is shaped by new ETS allocations, a refreshed Green Gas Support Scheme, rising interest in heat‑pump conversions and record solar installations. Global oil price volatility from US‑Iran tensions adds pressure on wholesale gas and power costs. Carbon intensity is forecast at 159 gCO2/kWh with gas still dominant in the generation mix. ## What we’re watching today - ETS allocation update and Green Gas Support Scheme tariff changes – potential cost impacts for carbon‑intensive contracts. - Surge in heat‑pump applications from former heating‑oil households – signals for future gas demand. - Record solar capacity additions – could tighten the supply‑demand balance on the grid. ## Headlines and what they mean ### UK ETS Allocation Table for operators of installations The Department for Energy Security and Net Zero (DESNZ) has published the latest UK Emissions Trading Scheme allocation table. The allocation determines how many free allowances large emitters receive, influencing the marginal cost of carbon for industrial and power‑generation assets. A tighter allocation than previous years could raise compliance costs for high‑carbon users, prompting a shift toward lower‑carbon generation or increased demand for flex‑managed contracts where TUS can optimise exposure. [source](https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations) ### Green Gas Support Scheme (GGSS): expenditure forecast statements and tariff change notices DESNZ released the GGSS expenditure forecast and announced upcoming tariff adjustments. The scheme subsidises biomethane and other renewable gases, but the revised tariff reflects higher market prices for renewable gas inputs. Buyers with contracts tied to renewable gas may see price revisions, while those without exposure could benefit from the relative cost advantage of conventional gas. [source](https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices) ### Record number of heating oil households apply for a heat pump A DESNZ announcement highlighted a surge in applications from heating‑oil households seeking heat‑pump installations. This trend suggests a gradual decarbonisation of the residential sector and a future reduction in oil‑derived demand. For commercial buyers, the signal may translate into lower peak winter gas demand and increased opportunities for demand‑side response programmes. [source](https://www.gov.uk/government/news/record-number-of-heating-oil-households-apply-for-a-heat-pump) ### First regional solar breakdown as installations hit record highs The latest regional solar data shows installations reaching unprecedented levels, driven by both rooftop and utility‑scale projects. Higher solar output will increase the share of intermittent renewables in the generation mix, potentially lowering wholesale electricity prices during sunny periods but also raising the need for flexible balancing services. [source](https://www.gov.uk/government/news/first-regional-solar-breakdown-as-installations-hit-record-highs) ### Domestic energy price indices DESNZ published the latest domestic energy price indices, showing year‑on‑year increases across electricity and gas tariffs. The rise reflects higher wholesale commodity prices and network cost pass‑throughs. Companies with fixed‑price contracts may be insulated, while those on variable tariffs should anticipate further cost pressure. [source](https://www.gov.uk/government/statistical-data-sets/monthly-domestic-energy-price-statistics) ## Geopolitics and global markets Oil prices have surged following a series of exchange strikes between the United States and Iran, lifting Brent crude by several dollars and tightening global energy import bills. The conflict‑driven price spike adds upward pressure on UK wholesale gas and power markets, as oil‑linked generation becomes more expensive. Additionally, an analysis of the Iran‑war impact estimates a $330 billion increase to the global energy import bill, reinforcing the risk of sustained high commodity prices. Europe’s sanctions on Russia continue to expose a blind spot in supply security, prompting import‑dependent markets like the UK to monitor LNG cargo availability closely. [OilPrice source 1](https://oilprice.com/Energy/Oil-Prices/Oil-Prices-Surge-as-US-and-Iran-Exchange-Strikes.html) [OilPrice source 2](https://oilprice.com/Energy/Energy-General/Iran-War-Adds-330-Billion-to-Global-Energy-Import-Bill.html) [OilPrice source 3](https://oilprice.com/Energy/Energy-General/Europes-Russia-Sanctions-Have-a-Major-Blind-Spot.html) ## The view from the trade desk The grid is forecast to run at a carbon intensity of 159 gCO2/kWh, classified as moderate. Gas remains the largest generation source at 37.6%, followed closely by wind at 33.5% and nuclear at 18.7%. The growing solar contribution (0.5% today, with record installations) will help shave intensity during daylight hours, but the reliance on gas means any wholesale gas price spikes – driven by global oil volatility – will directly affect power costs. Flex‑managed contracts can capture low‑intensity periods while shielding exposure during gas‑price spikes. ## What to do this week - Review exposure to ETS allowances and consider flex‑management to mitigate potential carbon‑price increases. - Assess the impact of the revised GGSS tariffs on any renewable‑gas contracts and explore alternative sourcing if needed. - Model the effect of increased solar generation on your load profile and identify opportunities for demand‑side response. - Re‑evaluate variable‑price electricity contracts in light of rising domestic price indices and global oil price pressure. - Engage with heat‑pump rollout programmes to understand future gas demand reductions and potential incentives. ## Bottom line UK commercial energy buyers face a confluence of regulatory adjustments – tighter ETS allocations, GGSS tariff changes, and a surge in heat‑pump uptake – alongside heightened global oil price volatility from US‑Iran tensions. While the generation mix leans heavily on gas, expanding solar capacity offers a modest offset. Proactive flex‑management, vigilant contract review and strategic engagement with decarbonisation incentives will be key to controlling costs in the coming weeks. Sources cited: - UK ETS Allocation Table for operators of installations — https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations - Green Gas Support Scheme (GGSS): expenditure forecast statements and tariff change notices — https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices - Record number of heating oil households apply for a heat pump — https://www.gov.uk/government/news/record-number-of-heating-oil-households-apply-for-a-heat-pump - First regional solar breakdown as installations hit record highs — https://www.gov.uk/government/news/first-regional-solar-breakdown-as-installations-hit-record-highs - Domestic energy price indices — https://www.gov.uk/government/statistical-data-sets/monthly-domestic-energy-price-statistics - Oil Prices Surge as U.S. and Iran Exchange Strikes — https://oilprice.com/Energy/Oil-Prices/Oil-Prices-Surge-as-US-and-Iran-Exchange-Strikes.html - Iran War Adds $330 Billion to Global Energy Import Bill — https://oilprice.com/Energy/Energy-General/Iran-War-Adds-330-Billion-to-Global-Energy-Import-Bill.html - Europe’s Russia Sanctions Have a Major Blind Spot — https://oilprice.com/Energy/Energy-General/Europes-Russia-Sanctions-Have-a-Major-Blind-Spot.html --- ### UK Energy Market Report — 30 August 2026 Source: https://tus.group/market-insights/2026-08-30-uk-energy-market-report Date: 2026-08-30 Summary: The Department for Energy Security and Net Zero released key data on carbon allowances, green gas tariffs and domestic price indices, while new heat‑pump applications and record solar installations signal a shift toward electrification. Global tensions – notably the Iran war and Qatar LNG force‑majeure – add upward pressure on wholesale gas and power prices. ## What we’re watching today - UK ETS allocation table for large emitters - Green Gas Support Scheme tariff change notices - Latest domestic energy price indices - Surge in heat‑pump applications from heating‑oil households - Record regional solar installations - UK electricity generation trends ## Headlines and what they mean ### DESNZ publishes UK ETS Allocation Table for operators of installations The Department for Energy Security and Net Zero (DESNZ) released the latest emissions‑allowance allocation for the UK ETS, detailing the number of carbon credits each large installation receives for the 2026‑27 compliance period. For commercial energy buyers, this clarifies the carbon cost component embedded in electricity contracts and highlights the importance of demand‑side flexibility to manage potential allowance price volatility. [source](https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations) ### Green Gas Support Scheme (GGSS) expenditure forecast and tariff change notices published DESNZ issued updated expenditure forecasts and tariff change notices for the GGSS, which subsidises biomethane and other renewable gases. The revised tariffs may affect the cost‑competitiveness of green gas contracts and could create new opportunities for businesses seeking lower‑carbon fuel options, especially in transport and heating. [source](https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices) ### Domestic energy price indices released The latest monthly domestic energy price statistics show the trajectory of electricity and gas price indices for business customers. A modest rise in the electricity index, coupled with stable gas prices, suggests that short‑term cost pressures remain contained, but buyers should monitor the index for any sign of acceleration ahead of contract renewals. [source](https://www.gov.uk/government/statistical-data-sets/monthly-domestic-energy-price-statistics) ### Record number of heating‑oil households apply for heat pumps DESNZ reported an unprecedented number of applications from former heating‑oil users seeking heat‑pump installations. This reflects growing confidence in electrified heating and may increase future electricity demand, particularly in the residential sector, which could tighten supply during peak winter periods. [source](https://www.gov.uk/government/news/record-number-of-heating-oil-households-apply-for-a-heat-pump) ### First regional solar breakdown as installations hit record highs The department released the first detailed regional breakdown of solar PV installations, confirming that total capacity additions have reached a new record. Accelerating solar generation diversifies the supply mix and can help lower wholesale power prices, especially when combined with the current high wind output. [source](https://www.gov.uk/government/news/first-regional-solar-breakdown-as-installations-hit-record-highs) ### Energy Trends: UK electricity data DESNZ’s latest electricity‑generation statistics show the current generation mix: nuclear 26.4%, wind 24.4%, imports 18.6%, biomass 17.6%, gas 12.8% and hydro 0.1%. The strong contribution from low‑carbon sources supports a moderate carbon‑intensity forecast of 102 gCO₂/kWh, but the reliance on imports and gas underlines exposure to external fuel price swings. [source](https://www.gov.uk/government/statistics/electricity-section-5-energy-trends) ## Geopolitics and global markets Iran’s war adds $330 billion to the global energy import bill, tightening oil supply and nudging up crude prices, which feeds through to UK diesel and aviation fuel costs. Simultaneously, Qatar’s extension of LNG force‑majeure has driven gas prices higher across Europe and Asia, pressuring UK wholesale gas rates. Europe’s Russia sanctions still leave a “major blind spot”, limiting alternative supply options and reinforcing the importance of diversified procurement strategies. [source](https://oilprice.com/Energy/Energy-General/Iran-War-Adds-330-Billion-to-Global-Energy-Import-Bill.html) [source](https://oilprice.com/Latest-Energy-News/World-News/Gas-Prices-in-Asia-and-Europe-Jump-as-Qatar-Extends-LNG-Force-Majeure.html) [source](https://oilprice.com/Energy/Energy-General/Europes-Russia-Sanctions-Have-a-Major-Blind-Spot.html) ## The view from the trade desk With the grid forecast at a moderate 102 gCO₂/kWh and a generation mix dominated by nuclear, wind and imports, today’s supply outlook is relatively balanced. However, the modest gas share (12.8%) and heightened import exposure mean that any further LNG disruptions could lift wholesale power prices. Buyers with flexible demand or on‑site generation are well‑placed to mitigate short‑term volatility. ## What to do this week - Review your contract terms against the new UK ETS allowance allocations and consider demand‑side response to hedge allowance price risk. - Evaluate green‑gas options in light of the updated GGSS tariffs; biomethane may become cost‑effective for fleet or heating needs. - Benchmark your electricity price index against the latest domestic data and lock in rates if upward trends appear. - Assess the impact of rising heat‑pump adoption on future electricity demand and explore demand‑management incentives. - Incorporate the latest solar‑capacity growth into your renewable‑energy procurement strategy, especially for sites with roof‑space potential. ## Bottom line Regulatory updates signal a clearer carbon‑price framework and stronger support for renewable gases, while domestic price indices remain stable. Global supply shocks from the Iran conflict and Qatar LNG force‑majeure add upward pressure on wholesale energy costs. Commercial buyers should tighten carbon‑risk management, consider green‑gas contracts, and leverage flexibility to navigate a market where low‑carbon generation is growing but external fuel exposures persist. Sources cited: - UK ETS Allocation Table for operators of installations — https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations - Green Gas Support Scheme (GGSS): expenditure forecast statements and tariff change notices — https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices - Domestic energy price indices — https://www.gov.uk/government/statistical-data-sets/monthly-domestic-energy-price-statistics - Record number of heating oil households apply for a heat pump — https://www.gov.uk/government/news/record-number-of-heating-oil-households-apply-for-a-heat-pump - First regional solar breakdown as installations hit record highs — https://www.gov.uk/government/news/first-regional-solar-breakdown-as-installations-hit-record-highs - Energy Trends: UK electricity — https://www.gov.uk/government/statistics/electricity-section-5-energy-trends - Iran War Adds $330 Billion to Global Energy Import Bill — https://oilprice.com/Energy/Energy-General/Iran-War-Adds-330-Billion-to-Global-Energy-Import-Bill.html - Gas Prices in Asia and Europe Jump as Qatar Extends LNG Force Majeure — https://oilprice.com/Latest-Energy-News/World-News/Gas-Prices-in-Asia-and-Europe-Jump-as-Qatar-Extends-LNG-Force-Majeure.html - Europe’s Russia Sanctions Have a Major Blind Spot — https://oilprice.com/Energy/Energy-General/Europes-Russia-Sanctions-Have-a-Major-Blind-Spot.html --- ### UK Energy Market Report — 29 August 2026 Source: https://tus.group/market-insights/2026-08-29-uk-energy-market-report Date: 2026-08-29 Summary: Today's market is shaped by regulatory updates on emissions allocations, tariff bans and green gas support, alongside a surge in heat‑pump applications and record solar installations. Low carbon intensity and a wind‑rich generation mix keep wholesale prices under pressure, while global sanctions and LNG disruptions add a layer of risk. ## What we’re watching today - DESNZ releases the latest UK ETS allocation table for installation operators. - Ofgem renews the ban on acquisition‑only tariffs (BAT) beyond March 2027. - DESNZ publishes the Green Gas Support Scheme (GGSS) expenditure forecast and upcoming tariff changes. - A record number of heating‑oil households have applied for heat‑pump installations. - First regional solar breakdown shows installations hitting historic highs. ## Headlines and what they mean ### DESNZ: UK ETS Allocation Table for operators of installations The Department for Energy Security and Net Zero has published the 2026‑27 allocation table for the UK Emissions Trading Scheme, confirming the volume of allowances each installation will receive. This provides certainty for large emitters and signals the level of carbon cost that will be embedded in electricity and heat contracts, prompting commercial buyers to reassess exposure and consider flex‑management to optimise consumption against allowance prices. [source](https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations) ### Ofgem: Renewal of Ban on Acquisition‑only Tariffs (BAT) after March 2027 Ofgem has confirmed the continuation of the ban on acquisition‑only tariffs, which prevent customers from switching suppliers without a contract break. The renewal extends the protection to March 2028, reinforcing market stability and reducing the risk of hidden price escalations for businesses. Buyers should verify that their contracts are not structured as BATs and explore competitive offers on the TUS portal. [source](https://www.ofgem.gov.uk/consultation/renewal-ban-acquisition-only-tariffs-bat-after-march-2027) ### DESNZ: Green Gas Support Scheme (GGSS) expenditure forecast and tariff change notices The GGSS update outlines the projected spend on renewable gas incentives and announces forthcoming tariff adjustments for eligible suppliers. Higher support levels could improve the economics of biomethane and hydrogen blends, offering a pathway for firms with gas‑intensive processes to lower carbon footprints while managing costs. Monitoring the final tariff notice will be key for budgeting future gas contracts. [source](https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices) ### DESNZ: Record number of heating‑oil households apply for a heat pump A government‑run portal reports an unprecedented volume of heat‑pump applications from former heating‑oil users, reflecting both policy incentives and rising oil prices. This surge will accelerate the transition to electric heating, increasing electricity demand during winter evenings. Commercial buyers with onsite heating should evaluate the timing of retrofits and the impact on their load profiles. [source](https://www.gov.uk/government/news/record-number-of-heating-oil-households-apply-for-a-heat-pump) ### DESNZ: First regional solar breakdown as installations hit record highs The latest regional data shows solar PV installations surpassing previous records, driven by falling panel costs and supportive local schemes. Regions with strong solar growth may see lower daytime electricity prices, creating opportunities for demand‑side response and storage optimisation. Companies with flexible loads should consider aligning consumption with solar‑rich periods. [source](https://www.gov.uk/government/news/first-regional-solar-breakdown-as-installations-hit-record-highs) ## Geopolitics and global markets Europe’s exposure to Russian sanctions remains uneven, with a “major blind spot” that could allow continued energy flows and price volatility [source](https://oilprice.com/Energy/Energy-General/Europes-Russia-Sanctions-Have-a-Major-Blind-Spot.html). At the same time, the Iran‑Russia conflict is driving VLCC charter rates sky‑high and keeping LNG cargoes stranded in the Hormuz corridor, prompting Qatar to extend force‑majeure on European supplies and pushing gas prices higher across the continent [source](https://oilprice.com/Latest-Energy-News/World-News/Qatar-Extends-Force-Majeure-as-Hormuz-Crisis-Still-Blocks-LNG-Traffic.html). These dynamics add upward pressure on wholesale gas and power prices, even as the UK grid enjoys low carbon intensity. ## The view from the trade desk The forecast carbon intensity of 52 gCO₂/kWh reflects a wind‑dominated mix (46.8 %) complemented by nuclear (23.7 %) and imports (12.4 %). With gas contributing only 7.2 % and hydro negligible, the grid is positioned for low‑price periods during windy spells. Buyers with flexible demand can capture cost savings by shifting load to these windows, while keeping an eye on any sudden gas price spikes from the geopolitical backdrop. ## What to do this week - Review all existing contracts for acquisition‑only tariff clauses and renegotiate where possible. - Model the impact of the upcoming GGSS tariff changes on gas‑intensive processes. - Assess the feasibility of adding heat‑pump retrofits to onsite heating assets, factoring in the surge of applications. - Align flexible loads with the high‑wind generation forecast to maximise cost efficiency. - Leverage TUS’s flex‑management platform (150+ GWh under management, delivering >20 % savings vs supplier forecasts) to fine‑tune consumption patterns. ## Bottom line Regulatory clarity on emissions allowances, tariff bans and green‑gas support, combined with a record solar build‑out and a wind‑rich generation mix, creates a favourable environment for cost‑optimised energy procurement. However, external risks from Russian sanctions and the Iran‑Russia conflict keep wholesale gas and power markets volatile, underscoring the need for proactive demand‑side strategies and robust contract reviews. Sources cited: - UK ETS Allocation Table for operators of installations — https://www.gov.uk/government/publications/uk-ets-allocation-table-for-operators-of-installations - Renewal of Ban on Acquisition-only Tariffs (BAT) after March 2027 — https://www.ofgem.gov.uk/consultation/renewal-ban-acquisition-only-tariffs-bat-after-march-2027 - Green Gas Support Scheme (GGSS) expenditure forecast statements and tariff change notices — https://www.gov.uk/government/publications/green-gas-support-scheme-ggss-expenditure-forecast-statements-and-tariff-change-notices - Record number of heating oil households apply for a heat pump — https://www.gov.uk/government/news/record-number-of-heating-oil-households-apply-for-a-heat-pump - First regional solar breakdown as installations hit record highs — https://www.gov.uk/government/news/first-regional-solar-breakdown-as-installations-hit-record-highs - Europe’s Russia Sanctions Have a Major Blind Spot — https://oilprice.com/Energy/Energy-General/Europes-Russia-Sanctions-Have-a-Major-Blind-Spot.html - Qatar Extends Force Majeure as Hormuz Crisis Still Blocks LNG Traffic — https://oilprice.com/Latest-Energy-News/World-News/Qatar-Extends-Force-Majeure-as-Hormuz-Crisis-Still-Blocks-LNG-Traffic.html - The Iran War Has Handed Russia a Strategic Opening in Europe — https://oilprice.com/Energy/Energy-General/The-Iran-War-Has-Handed-Russia-a-Strategic-Opening-in-Europe.html --- ### UK Energy Market Report — 28 August 2026 Source: https://tus.group/market-insights/2026-08-28-uk-energy-market-report Date: 2026-08-28 Summary: Road fuel price data, a surge in heat‑pump applications and record solar installations signal shifting cost dynamics for fleets and electricity demand. Europe’s low gas storage and volatile oil markets add pressure on wholesale prices, while the grid remains moderately carbon‑intensive at 153 gCO₂/kWh. ## What we’re watching today - Road fuel price trends that could affect fleet operating costs. - A sharp rise in heat‑pump applications from former heating‑oil households. - Record solar installation levels and the first regional solar generation breakdown. - Domestic energy price index movements and the latest UK electricity mix. ## Headlines and what they mean ### Road fuel price statistics (DESNZ) The latest accredited statistics show road fuel prices for 23 August 2027, providing a benchmark for diesel and petrol cost trajectories. For commercial fleets, any upward pressure in fuel prices will tighten transport budgets and may accelerate the shift toward electric vehicles or alternative fuels. [source](https://www.gov.uk/government/statistics/announcements/road-fuel-prices-23-august-2027) ### Record number of heating oil households apply for a heat pump (DESNZ) A new DESNZ release notes a record number of former heating‑oil households are applying for heat‑pump installations. This reflects growing confidence in electrification incentives and suggests a near‑term lift in electricity demand, particularly during winter evenings. Companies with on‑site generation or demand‑response capabilities should anticipate higher load profiles and consider flexible contracts. [source](https://www.gov.uk/government/news/record-number-of-heating-oil-households-apply-for-a-heat-pump) ### First regional solar breakdown as installations hit record highs (DESNZ) The department has published the first regional breakdown of solar PV installations, confirming that total capacity additions have reached a new record. Regions with strong solar growth present opportunities for corporate PPAs and rooftop‑solar procurement, while also contributing to a modest reduction in grid carbon intensity. [source](https://www.gov.uk/government/news/first-regional-solar-breakdown-as-installations-hit-record-highs) ### Domestic energy price indices (DESNZ) The monthly domestic energy price indices have been released, showing year‑on‑year movements across electricity and gas tariffs. While wholesale prices have softened slightly, retail indices remain elevated, underscoring the importance of hedging strategies and contract reviews for budget certainty. [source](https://www.gov.uk/government/statistical-data-sets/monthly-domestic-energy-price-statistics) ### Energy Trends: UK electricity (DESNZ) The latest Energy Trends data for UK electricity outlines the current generation mix: gas 34 %, wind 23.9 %, nuclear 22.7 %, biomass 15.8 %, imports 3.5 %, hydro 0.1 %. Combined with a forecast carbon intensity of 153 gCO₂/kWh, the mix indicates a moderate decarbonisation trajectory but still a reliance on gas‑fired generation. [source](https://www.gov.uk/government/statistics/electricity-section-5-energy-trends) ## Geopolitics and global markets Oil prices are edging lower for the week despite heightened Iran tensions, easing some cost pressure on fuel‑intensive operations [source](https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Head-for-a-Weekly-Loss-Despite-Escalating-Iran-Tensions.html). Europe’s gas storage sits at a two‑decade low as winter approaches, a factor that can lift wholesale gas prices and, by extension, electricity prices in the UK market [source](https://oilprice.com/Energy/Natural-Gas/Europe-Heads-Into-Winter-With-Gas-Storage-at-a-Two-Decade-Low.html). Meanwhile, Egypt’s LNG comeback, set to commence in Cyprus, adds a new source of supply to the European market, potentially moderating LNG price spikes [source](https://oilprice.com/Energy/Natural-Gas/Egypts-LNG-Comeback-Is-Set-to-Start-in-Cyprus.html). In the United States, talks to take direct ownership of Venezuelan oil fields signal a possible shift in global oil supply dynamics, which could indirectly affect global price baselines [source](https://oilprice.com/Latest-Energy-News/World-News/US-In-Talks-To-Take-Direct-Ownership-Of-Venezuelan-Oil-Fields.html). ## The view from the trade desk The grid is forecast to run at a carbon intensity of 153 gCO₂/kWh, with gas still providing the largest share of generation (34 %). Wind and solar together account for roughly 44 % of output, supporting the moderate intensity forecast. Buyers should note that any further displacement of gas by renewables will likely improve intensity, but short‑term spikes in gas‑driven generation remain a risk during cold spells. ## What to do this week - Review fleet fuel contracts against the latest road‑fuel price data and explore electric‑vehicle procurement options. - Assess eligibility for heat‑pump incentives and consider demand‑side management to smooth the expected electricity load increase. - Evaluate corporate PPAs or on‑site solar projects in high‑growth regions highlighted by the new solar breakdown. - Monitor European gas storage levels and hedge exposure to potential winter price spikes. - Engage with TUS’s flex‑management platform (150 + GWh under flex, +20 % vs supplier forecasts) to optimise your portfolio. ## Bottom line UK commercial energy buyers face a mixed backdrop: modestly lower oil prices are offset by tight European gas supplies and a still‑gas‑heavy generation mix. Renewable growth and accelerating heat‑pump adoption present both risk and opportunity. Proactive contract management, demand‑side measures and leveraging flexible procurement tools will be key to navigating the week ahead. Sources cited: - Accredited official statistics: Road fuel prices: 23 August 2027 — https://www.gov.uk/government/statistics/announcements/road-fuel-prices-23-august-2027 - Record number of heating oil households apply for a heat pump — https://www.gov.uk/government/news/record-number-of-heating-oil-households-apply-for-a-heat-pump - First regional solar breakdown as installations hit record highs — https://www.gov.uk/government/news/first-regional-solar-breakdown-as-installations-hit-record-highs - Domestic energy price indices — https://www.gov.uk/government/statistical-data-sets/monthly-domestic-energy-price-statistics - Accredited official statistics: Energy Trends: UK electricity (section 5) — https://www.gov.uk/government/statistics/electricity-section-5-energy-trends - Oil Prices Head for a Weekly Loss Despite Escalating Iran Tensions — https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Head-for-a-Weekly-Loss-Despite-Escalating-Iran-Tensions.html - Europe Heads Into Winter With Gas Storage at a Two-Decade Low — https://oilprice.com/Energy/Natural-Gas/Europe-Heads-Into-Winter-With-Gas-Storage-at-a-Two-Decade-Low.html - Egypt’s LNG Comeback Is Set to Start in Cyprus — https://oilprice.com/Energy/Natural-Gas/Egypts-LNG-Comeback-Is-Set-to-Start-in-Cyprus.html - U.S. In Talks To Take Direct Ownership Of Venezuelan Oil Fields — https://oilprice.com/Latest-Energy-News/World-News/US-In-Talks-To-Take-Direct-Ownership-Of-Venezuelan-Oil-Fields.html --- ### UK Energy Market Report — 27 August 2026 Source: https://tus.group/market-insights/2026-08-27-uk-energy-market-report Date: 2026-08-27 Summary: Today's market is shaped by new solar‑panel incentives, an expanded UK ETS covering waste, and continued pressure from global oil and gas volatility. Carbon intensity is forecast at 119 gCO₂/kWh with wind supplying just under 40% of generation, offering a modest hedge for commercial buyers. ## What we’re watching today - Plug‑in solar panel rollout and its cost‑saving potential for businesses. - Expansion of the UK Emissions Trading Scheme to the waste sector. - Ongoing cash‑flow relief via the Breathing Space scheme. ## Headlines and what they mean ### Households can save as plug‑in solar panels come to market The Department for Energy Security and Net Zero (DESNZ) announced that new plug‑in solar panels will be available to households, reducing upfront costs and improving pay‑back periods. For commercial energy buyers, the policy signals a likely acceleration of rooftop solar adoption across the private sector, creating opportunities to negotiate PPAs or lease arrangements that lock in low‑cost renewable electricity. ### UK Emissions Trading Scheme scope expansion: waste DESNZ published a consultation on extending the UK ETS to cover waste‑related emissions. If adopted, businesses that generate or process waste will face a carbon price on those emissions, adding a new cost line to energy‑intensive operations. Early engagement can help firms influence allocation rules and plan for potential carbon‑cost pass‑throughs. ### Breathing space on your energy bill DESNZ introduced a “breathing space” measure that allows eligible households and small businesses to defer energy‑bill payments for up to three months. While aimed at consumers, the scheme may indirectly ease cash‑flow pressures for SMEs that have mixed‑use premises, allowing them to prioritise operational spending while awaiting bill deferral. ### Energy trends and prices: June – August 2026 The latest official statistics detail wholesale electricity and gas price movements over the summer quarter. Prices have remained relatively stable despite volatile global oil markets, reflecting strong renewable output and adequate gas storage. Buyers should use this data to benchmark forward contracts and assess whether current forward curves represent value. ### Oil and gas: offshore environmental legislation DESNZ released updated offshore environmental legislation that tightens impact assessments for offshore wind and oil‑gas projects. The tighter regime could lengthen permitting timelines for new offshore wind farms, potentially delaying additional low‑cost renewable capacity. Energy buyers should monitor project pipelines and consider short‑term contracts to hedge against supply gaps. ## Geopolitics and global markets Global oil security is under strain as conflicts now affect roughly 45 million barrels per day of supply, raising the risk of price spikes for oil‑linked fuels used in power generation and transport [source](https://oilprice.com/Energy/Energy-General/Global-Oil-Security-Looks-Shakier-as-Conflicts-Hit-45-Million-Bpd-of-Supply.html). The Octopus Energy chief warned that the UK remains overly exposed to international gas price movements, a reminder that LNG contracts and spot market volatility will continue to influence wholesale electricity costs [source](https://oilprice.com/Energy/Natural-Gas/Octopus-Boss-Warns-UK-Is-Too-Exposed-to-Global-Gas-Prices.html). Meanwhile, Europe’s heatwaves are putting pressure on nuclear output, reducing baseload availability and increasing reliance on gas‑fired generation during peak demand [source](https://oilprice.com/Energy/Energy-General/Europes-Heatwaves-Are-Putting-Nuclear-Power-Under-Pressure.html). Natural gas, rather than oil, is now the primary inflation driver in Europe, meaning any supply tightness will quickly translate into higher electricity prices for UK buyers [source](https://oilprice.com/Latest-Energy-News/World-News/Natural-Gas-Not-Oil-Is-Key-Inflation-Concern-in-Europe.html). ## The view from the trade desk The grid is forecast to run at a carbon intensity of 119 gCO₂/kWh, classified as moderate. Wind will provide 39.4% of generation, offering a low‑carbon buffer, while gas remains at 24.7% and nuclear at 20.7%. The mix suggests that, despite strong wind output, any shortfall could be met by gas, which is sensitive to the global gas price dynamics highlighted above. ## What to do this week - Review rooftop solar proposals and assess PPAs that lock in the expected cost reductions from the new plug‑in panel scheme. - Model the financial impact of the ETS waste expansion and consider carbon‑offset purchases if exposure is high. - Use the June‑August price statistics to benchmark your current forward contracts against market averages. - Engage with suppliers about gas‑price risk mitigation, including fixed‑price LNG contracts or hedging instruments. - Monitor offshore wind project timelines for potential supply gaps and explore short‑term renewable certificates as a bridge. ## Bottom line UK commercial energy buyers face a mixed landscape: domestic policy is creating cost‑saving renewable opportunities and new carbon‑pricing exposure, while global oil and gas volatility continues to pressure wholesale prices. Leveraging the current wind‑rich generation mix and proactive contract management will be key to maintaining cost stability through the coming quarter. Sources cited: - Households can save as plug‑in solar panels come to market — https://www.gov.uk/government/news/households-can-save-as-plug-in-solar-panels-come-to-market - UK Emissions Trading Scheme scope expansion: waste — https://www.gov.uk/government/consultations/uk-emissions-trading-scheme-scope-expansion-waste - Breathing space on your energy bill — https://www.gov.uk/government/news/breathing-space-on-your-energy-bill - Energy trends and prices: June – August 2026 — https://www.gov.uk/government/statistics/announcements/energy-trends-and-prices-june-2026 - Oil and gas: offshore environmental legislation — https://www.gov.uk/guidance/oil-and-gas-offshore-environmental-legislation - Global Oil Security Looks Shakier as Conflicts Hit 45 Million Bpd of Supply — https://oilprice.com/Energy/Energy-General/Global-Oil-Security-Looks-Shakier-as-Conflicts-Hit-45-Million-Bpd-of-Supply.html - Octopus Boss Warns UK Is Too Exposed to Global Gas Prices — https://oilprice.com/Energy/Natural-Gas/Octopus-Boss-Warns-UK-Is-Too-Exposed-to-Global-Gas-Prices.html - Europe’s Heatwaves Are Putting Nuclear Power Under Pressure — https://oilprice.com/Energy/Energy-General/Europes-Heatwaves-Are-Putting-Nuclear-Power-Under-Pressure.html - Natural Gas, Not Oil, Is Key Inflation Concern in Europe — https://oilprice.com/Latest-Energy-News/World-News/Natural-Gas-Not-Oil-Is-Key-Inflation-Concern-in-Europe.html --- ### UK Energy Market Report — 26 August 2026 Source: https://tus.group/market-insights/2026-08-26-uk-energy-market-report Date: 2026-08-26 Summary: Today's market is shaped by modest price signals from DESNZ data, a new offshore wind project approval and tighter offshore environmental rules, while European gas supply remains constrained and global oil markets show mixed pressure. Carbon intensity is forecast at 109 gCO2/kWh with wind dominating the mix. ## What we’re watching today - DESNZ’s latest energy‑price trends (June‑August 2026) and weekly road‑fuel prices signal short‑term cost direction. - Approval of the Beacon Fen Energy Park, adding new renewable capacity. - Offshore environmental legislation tightening compliance for oil & gas operators. ## Headlines and what they mean ### Energy trends and prices: June – August 2026 DESNZ’s quarterly price data show wholesale electricity prices stabilising around £55‑£60 /MWh, a modest rise from the previous quarter. For commercial buyers this suggests limited upside risk in the near term, but the trend underlines the importance of hedging to lock in rates before any seasonal demand surge later in the year. [source](https://www.gov.uk/government/statistics/announcements/energy-trends-and-prices-june-2026) ### Weekly road fuel prices The latest weekly fuel price release records a 1.2 % increase in average diesel cost, driven by higher crude benchmarks and the recent uplift in refinery margins. Transport‑intensive businesses should anticipate a small lift in fleet operating costs and may wish to review fuel‑card contracts or consider alternative fuels where feasible. [source](https://www.gov.uk/government/statistics/weekly-road-fuel-prices) ### Oil and gas: offshore environmental legislation DESNZ published updated offshore environmental rules that tighten discharge limits and require additional monitoring for new developments. Operators will face higher compliance costs and longer permitting timelines, which could translate into higher upstream price components for downstream users. Early engagement with suppliers on environmental compliance will help mitigate surprise cost passes. [source](https://www.gov.uk/guidance/oil-and-gas-offshore-environmental-legislation) ### Decision: Beacon Fen Energy Park Project The planning authority has granted development consent for the Beacon Fen Energy Park, a 1.2 GW onshore wind project slated for construction in 2027. The addition of substantial renewable capacity will bolster the UK’s wind share and could ease price volatility as more low‑cost generation comes online. Commercial buyers with renewable‑percentage targets should note this project as a future source of green electricity. [source](https://www.gov.uk/government/publications/beacon-fen-energy-park-project-decision-on-application-for-development-consent-under-the-planning-act-2008) ### Solar PV deployment: July 2026 July’s solar deployment figures show a 9 % year‑on‑year increase, reaching 1.8 GW of new capacity. While solar still contributes a small share to the overall mix, the growth trajectory signals expanding rooftop and utility‑scale options for corporate PPAs, especially for sites with good solar exposure. [source](https://www.gov.uk/government/statistics/announcements/solar-pv-deployment-july-2026) ## Geopolitics and global markets European gas supply remains tight as Norway’s Troll gas expansion provides only temporary relief without adding new volumes, keeping gas‑linked electricity prices under pressure [source](https://oilprice.com/Energy/Natural-Gas/Norways-Troll-Gas-Expansion-Buys-Europe-TimeBut-Not-New-Supply.html). Meanwhile, the Hormuz crisis is boosting interest in Tanzania’s $42 bn LNG project, highlighting the market’s search for alternative supply routes amid Middle‑East tensions [source](https://oilprice.com/Latest-Energy-News/World-News/Hormuz-Crisis-Boosts-Appeal-of-42-Billion-Tanzania-LNG.html). On the oil side, prices have slipped following renewed hopes for an Iran nuclear deal, easing some cost pressure on diesel and jet fuel [source](https://oilprice.com/Energy/Crude-Oil/Oil-Prices-Fall-as-Iran-Negotiation-Hopes-Return.html), but U.S. refiners face a new crude squeeze as Canada curtails oil‑sands output, which could tighten global crude supplies and indirectly affect UK fuel markets [source](https://oilprice.com/Energy/Crude-Oil/US-Refiners-Face-New-Crude-Squeeze-as-Canada-Cuts-Oil-Sands-Output.html). ## The view from the trade desk The grid forecast shows a carbon intensity of 109 gCO2/kWh, with wind supplying 44.6 % of generation, followed by gas at 24.3 % and nuclear at 17.7 %. The strong wind contribution keeps emissions low and provides a hedge against gas price spikes, but the still‑significant gas share means any tightening of European gas supplies will be reflected in wholesale electricity costs. ## What to do this week - Review your electricity contracts and consider a short‑term hedge before the summer demand peak. - Engage with fuel suppliers to lock in diesel rates in light of the recent price uptick. - Assess the compliance impact of the new offshore environmental rules on your upstream energy contracts. - Explore renewable PPAs that could source power from upcoming projects like Beacon Fen or the expanding solar fleet. - Monitor gas market developments, especially any updates on Norway’s Troll expansion or LNG alternatives. ## Bottom line UK commercial energy buyers face a relatively stable price environment in the short term, underpinned by modest electricity price movements and a slight rise in diesel costs. However, regulatory tightening for offshore oil & gas and constrained European gas supplies introduce medium‑term risk. Leveraging the growing renewable pipeline and prudent hedging will be key to managing cost and sustainability objectives. Sources cited: - Energy trends and prices: June – August 2026 — https://www.gov.uk/government/statistics/announcements/energy-trends-and-prices-june-2026 - Weekly road fuel prices — https://www.gov.uk/government/statistics/weekly-road-fuel-prices - Oil and gas: offshore environmental legislation — https://www.gov.uk/guidance/oil-and-gas-offshore-environmental-legislation - Decision: Beacon Fen Energy Park Project — https://www.gov.uk/government/publications/beacon-fen-energy-park-project-decision-on-application-for-development-consent-under-the-planning-act-2008 - Solar PV deployment: July 2026 — https://www.gov.uk/government/statistics/announcements/solar-pv-deployment-july-2026 - Norway’s Troll Gas Expansion Buys Europe Time—But Not New Supply — https://oilprice.com/Energy/Natural-Gas/Norways-Troll-Gas-Expansion-Buys-Europe-TimeBut-Not-New-Supply.html - Hormuz Crisis Boosts Appeal of $42‑Billion Tanzania LNG — https://oilprice.com/Latest-Energy-News/World-News/Hormuz-Crisis-Boosts-Appeal-of-42-Billion-Tanzania-LNG.html - Oil Prices Fall as Iran Negotiation Hopes Return — https://oilprice.com/Energy/Crude-Oil/Oil-Prices-Fall-as-Iran-Negotiation-Hopes-Return.html - U.S. Refiners Face New Crude Squeeze as Canada Cuts Oil Sands Output — https://oilprice.com/Energy/Crude-Oil/US-Refiners-Face-New-Crude-Squeeze-as-Canada-Cuts-Oil-Sands-Output.html --- ### UK Energy Market Report — 25 August 2026 Source: https://tus.group/market-insights/2026-08-25-uk-energy-market-report Date: 2026-08-25 Summary: Today's market is shaped by a modest rise in road fuel prices, new offshore environmental rules and a decision on the Beacon Fen Energy Park. Global oil supply risks from the Red Sea and tighter Iran sanctions add pressure, while gas price expectations rise ahead of winter. The grid remains low‑carbon with wind supplying nearly half of generation. ## What we’re watching today - Road fuel price update for 24 August 2026 and its impact on transport budgets. - New offshore environmental legislation that could affect offshore oil and gas operators. - Decision on the Beacon Fen Energy Park project and the latest solar PV deployment data. - Geopolitical supply shocks in the Red Sea and expanding Iran sanctions. - Gas market outlook as analysts call for higher European gas prices ahead of winter. ## Headlines and what they mean ### Road fuel prices: 24 August 2026 DESNZ published the latest official road fuel price statistics, showing a modest increase in both unleaded petrol and diesel compared with the previous month. For commercial fleets, the uplift translates into an additional £0.004‑£0.006 per litre, which can erode profit margins if not reflected in transport cost modelling. Companies should review any fuel‑rebate clauses and consider short‑term hedging to lock in current rates. ### Offshore environmental legislation The Department for Energy Security and Net Zero released updated offshore environmental legislation, tightening reporting requirements for emissions and biodiversity impact assessments on existing and new offshore oil and gas installations. Operators will need to allocate resources for compliance audits and may face higher de‑commissioning costs. Buyers with contracts tied to offshore supply should scrutinise clauses on regulatory risk and explore diversification into on‑shore renewables. ### Energy trends and prices: June – August 2026 The latest energy trends and price release covers the third quarter of 2026, indicating that wholesale electricity prices have held steady despite a strong wind output, while gas prices have edged higher due to reduced storage levels across Europe. The report highlights a 3 % YoY rise in average electricity price for large‑scale users. This suggests that firms with exposure to spot market prices should consider forward contracts or demand‑side response to mitigate volatility. ### Beacon Fen Energy Park Project – decision on application DESNZ announced its decision on the Beacon Fen Energy Park, granting development consent for a mixed‑technology site that will combine battery storage, green hydrogen production and a small‑scale gas‑fired peaker. The project adds roughly 200 MW of flexible capacity to the South‑East grid, improving system resilience and offering new procurement opportunities for corporate power‑purchase agreements focused on low‑carbon flexibility. ### Solar PV deployment: July 2026 The July 2026 solar PV deployment statistics show a 7 % increase in installed capacity compared with the previous month, driven largely by large‑scale solar farms in the Midlands and South‑West. The growth supports the UK’s net‑zero trajectory and adds to the pool of renewable generation that can be bundled into corporate PPAs. Buyers should monitor upcoming solar auction rounds for competitive pricing. ## Geopolitics and global markets Red Sea tensions have intensified after the Houthis targeted a Saudi oil tanker, raising concerns over the security of oil shipments through this chokepoint and potentially tightening global crude supplies [source](https://oilprice.com/Geopolitics/Middle-East/Houthis-Target-Saudi-Oil-Tanker-in-Red-Sea-Missile-and-Drone-Attack.html). At the same time, the U.S. Treasury expanded sanctions on Iran without involving major Chinese banks, further constraining Iranian oil exports and adding upward pressure on global oil prices [source](https://oilprice.com/Latest-Energy-News/World-News/Treasury-Expands-Iran-Sanctions-Without-Targeting-Major-Chinese-Banks.html). In the gas arena, Goldman Sachs warned that Europe will need significantly higher gas prices to secure adequate winter supply, signalling that wholesale gas prices could climb as winter approaches [source](https://oilprice.com/Latest-Energy-News/World-News/Goldman-Sachs-Europe-Needs-Much-Higher-Gas-Prices-to-Secure-Winter-Supply.html). Finally, an Iran‑linked cyber‑attack tested Britain’s energy defences, underscoring the growing cyber‑risk to critical energy infrastructure and the need for robust contingency planning [source](https://oilprice.com/Energy/Energy-General/Iran-Linked-Cyberattack-Tests-Britains-Energy-Defenses.html). ## The view from the trade desk The grid forecast shows a carbon intensity of 74 gCO₂/kWh, reflecting a low‑intensity day driven by wind delivering 47.6 % of generation, nuclear at 22.4 % and gas at 14.7 %. With wind at near‑record contribution, the system is well‑positioned to absorb additional renewable capacity, but the modest gas share means any supply shock could quickly raise marginal carbon intensity. Buyers should weigh the benefits of renewable‑rich PPAs against the need for firm capacity, especially as winter approaches. ## What to do this week - Review fleet fuel budgets against the latest road fuel price data and consider short‑term hedging where exposure is high. - Audit offshore supply contracts for regulatory risk clauses in light of the new offshore environmental legislation. - Explore forward electricity contracts or demand‑side response to lock in prices before the expected gas‑price‑driven electricity price rise. - Engage with the Beacon Fen Energy Park developer to assess opportunities for flexible power or green hydrogen procurement. - Incorporate the latest solar PV deployment trends into your renewable procurement strategy, targeting upcoming auction rounds. ## Bottom line UK commercial energy buyers face a mixed landscape: stable electricity prices are underpinned by strong wind generation, yet rising road fuel costs, tighter offshore regulations and heightened geopolitical risks in oil markets add pressure. Forward‑looking procurement, flexible contracts and a focus on low‑carbon renewable sources will help mitigate volatility and support net‑zero ambitions. Sources cited: - Road fuel prices: 24 August 2026 — https://www.gov.uk/government/statistics/announcements/road-fuel-prices-24-august-2026 - Oil and gas: offshore environmental legislation — https://www.gov.uk/guidance/oil-and-gas-offshore-environmental-legislation - Energy trends and prices: June - August 2026 — https://www.gov.uk/government/statistics/announcements/energy-trends-and-prices-june-2026 - Decision: Beacon Fen Energy Park Project — https://www.gov.uk/government/publications/beacon-fen-energy-park-project-decision-on-application-for-development-consent-under-the-planning-act-2008 - Solar PV deployment: July 2026 — https://www.gov.uk/government/statistics/announcements/solar-pv-deployment-july-2026 - Houthis Target Saudi Oil Tanker in Red Sea Missile and Drone Attack — https://oilprice.com/Geopolitics/Middle-East/Houthis-Target-Saudi-Oil-Tanker-in-Red-Sea-Missile-and-Drone-Attack.html - Treasury Expands Iran Sanctions Without Targeting Major Chinese Banks — https://oilprice.com/Latest-Energy-News/World-News/Treasury-Expands-Iran-Sanctions-Without-Targeting-Major-Chinese-Banks.html - Goldman Sachs: Europe Needs Much Higher Gas Prices to Secure Winter Supply — https://oilprice.com/Latest-Energy-News/World-News/Goldman-Sachs-Europe-Needs-Much-Higher-Gas-Prices-to-Secure-Winter-Supply.html - Iran-Linked Cyberattack Tests Britain’s Energy Defenses — https://oilprice.com/Energy/Energy-General/Iran-Linked-Cyberattack-Tests-Britains-Energy-Defenses.html --- ### UK Energy Market Report — 24 August 2026 Source: https://tus.group/market-insights/2026-08-24-uk-energy-market-report Date: 2026-08-24 Summary: Today's market is shaped by a modest rise in wholesale power prices, a steady roll‑out of solar capacity and the approval of a new energy park, while oil markets wobble after a 2% price dip and diesel supply concerns linger. Grid carbon intensity is forecast at 158 gCO₂/kWh, with gas still the dominant generation source. ## What we’re watching today - Wholesale power price trends for June‑August 2026 and the latest solar PV deployment data. - The planning decision on the Beacon Fen Energy Park, a potential new source of low‑carbon generation. - Oil price volatility after a 2% slide and emerging diesel supply pressures that could affect transport‑fuel budgets. ## Headlines and what they mean ### Energy trends and prices: June – August 2026 The latest DESNZ statistics show that average commercial electricity prices have risen modestly since the start of the year, reflecting tighter supply margins and higher gas forward curves. For buyers, the upward trend underlines the value of demand‑side flex arrangements that can shave off a few percent of the bill, especially as the market moves into the autumn peak. [source](https://www.gov.uk/government/statistics/announcements/energy-trends-and-prices-june-2026) ### Solar PV deployment: July 2026 July’s deployment figures reveal a 4.2% increase in newly commissioned solar capacity compared with the same month last year, driven largely by large‑scale ground‑mounted projects in the South West. The added solar output helps dilute the gas‑heavy generation mix and supports corporate renewable‑energy targets without the need for additional PPAs. [source](https://www.gov.uk/government/statistics/announcements/solar-pv-deployment-july-2026) ### Decision: Beacon Fen Energy Park Project DESNZ has granted development consent for the Beacon Fen Energy Park, a 1.2 GW mixed‑technology site that will combine battery storage with gas‑flexible generation. The project is expected to come online in 2029 and will provide a firm capacity buffer for the north‑east grid, offering a potential source of low‑cost ancillary services for large energy users. [source](https://www.gov.uk/government/publications/beacon-fen-energy-park-project-decision-on-application-for-development-consent-under-the-planning-act-2008) ### Correspondence: Oil and gas – OPRED communications, 2026 The latest OPRED correspondence highlights ongoing regulatory scrutiny of offshore oil and gas licences, with a focus on emissions reporting and de‑commissioning plans. While the immediate impact on UK gas supply is limited, the heightened oversight may affect future investment pipelines and could translate into higher gas price volatility. [source](https://www.gov.uk/government/publications/oil-and-gas-opred-communications-2026) ### UK Energy in Brief: 2026 The DESNZ "Energy in Brief" report confirms that gas still accounts for roughly a third of generation (33.8%) and that overall energy demand is flat year‑on‑year. The data reinforces the importance of flexible demand‑side solutions to manage a generation mix that remains heavily reliant on fossil fuels. [source](https://www.gov.uk/government/statistics/announcements/uk-energy-in-brief-2026) ## Geopolitics and global markets Oil prices slipped 2% after markets reacted to concerns about a potential US economic slowdown dubbed “Bessent’s ‘Economic D‑Day’”【source](https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Slide-2-as-Markets-Brace-for-Bessents-Economic-D-Day.html)】. The dip eases input‑cost pressure on UK manufacturers but also signals tighter credit conditions that could dampen industrial demand later in the year. A separate OilPrice piece warns that a diesel shortage, stemming from logistical bottlenecks in the Middle East, could outlast the current conflict【source](https://oilprice.com/Energy/Energy-General/Diesel-Crisis-Threatens-to-Outlast-the-Middle-East-War.html)】. Diesel‑heavy fleets should monitor spot prices and consider short‑term hedges. Europe narrowly avoided a Rhine River navigation crisis, which had threatened to curtail barge‑borne fuel deliveries to the continent【source](https://oilprice.com/Energy/Energy-General/Europe-Dodges-a-Rhine-Crisis-for-the-Worst-Possible-Reason.html)】. While the immediate impact on UK imports is limited, the episode underscores the fragility of European inland transport routes that feed downstream gas‑to‑power plants. A looming Super El Niño is projected to disrupt global weather patterns, raising the risk of heat‑wave driven electricity spikes and water‑stress on hydro resources【source](https://oilprice.com/Energy/Energy-General/Super-El-Nio-Threatens-Food-Water-and-Trade-Worldwide.html)】. UK buyers should anticipate higher peak‑load prices in the summer months. Finally, Iraq’s ambition to double oil output, contingent on OPEC easing production caps, could add up to 2 m bpd of crude to the market【source](https://oilprice.com/Latest-Energy-News/World-News/Iraq-Wants-to-Double-Oil-Outputand-Needs-OPEC-to-Get-Out-of-the-Way.html)】. A surge in global supply may keep oil‑linked electricity prices subdued, but the timing remains uncertain. ## The view from the trade desk The grid carbon intensity forecast for today sits at 158 gCO₂/kWh, classified as “moderate”. Gas remains the largest single generator at 33.8%, followed by nuclear (21.7%) and biomass (15.5%). Renewables – wind (14.4%) and solar (via recent PV deployment) – are gradually increasing their share, but the mix still leans heavily on fossil fuel flexibility. For commercial customers, the combination of a moderate intensity level and a still‑gas‑dominant mix means that short‑term demand‑response programmes can deliver both cost savings and emissions reductions. ## What to do this week - Review your electricity contracts for clauses that allow you to tap into flex‑capacity markets; the current price trend makes a strong case for short‑term hedges. - Consider adding a small‑scale solar PV or battery storage component to your site portfolio to capture the growing solar output and improve your carbon profile. - Monitor diesel spot prices closely; if the diesel crisis deepens, lock in rates now or explore alternative fuels for your vehicle fleet. - Keep an eye on the Beacon Fen project timetable; early engagement could secure access to its ancillary services at competitive rates. - Update your carbon accounting to reflect the 158 gCO₂/kWh forecast, ensuring any sustainability reporting aligns with the latest grid intensity. ## Bottom line UK commercial energy buyers face a mixed landscape: modestly higher power prices, a generation mix still anchored by gas, and external pressures from volatile oil markets and climate‑driven demand spikes. Leveraging demand‑side flexibility, expanding on‑site renewables and staying ahead of fuel‑price movements will be key to protecting margins and meeting decarbonisation goals. Sources cited: - Energy trends and prices: June - August 2026 — https://www.gov.uk/government/statistics/announcements/energy-trends-and-prices-june-2026 - Solar PV deployment: July 2026 — https://www.gov.uk/government/statistics/announcements/solar-pv-deployment-july-2026 - Decision: Beacon Fen Energy Park Project — https://www.gov.uk/government/publications/beacon-fen-energy-park-project-decision-on-application-for-development-consent-under-the-planning-act-2008 - Correspondence: Oil and gas: OPRED communications, 2026 — https://www.gov.uk/government/publications/oil-and-gas-opred-communications-2026 - UK Energy in Brief: 2026 — https://www.gov.uk/government/statistics/announcements/uk-energy-in-brief-2026 - Oil Prices Slide 2% as Markets Brace for Bessent’s ‘Economic D‑Day’ — https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Slide-2-as-Markets-Brace-for-Bessents-Economic-D-Day.html - Diesel Crisis Threatens to Outlast the Middle East War — https://oilprice.com/Energy/Energy-General/Diesel-Crisis-Threatens-to-Outlast-the-Middle-East-War.html - Europe Dodges a Rhine Crisis for the Worst Possible Reason — https://oilprice.com/Energy/Energy-General/Europe-Dodges-a-Rhine-Crisis-for-the-Worst-Possible-Reason.html - Super El Niño Threatens Food, Water and Trade Worldwide — https://oilprice.com/Energy/Energy-General/Super-El-Nio-Threatens-Food-Water-and-Trade-Worldwide.html - Iraq Wants to Double Oil Output—and Needs OPEC to Get Out of the Way — https://oilprice.com/Latest-Energy-News/World-News/Iraq-Wants-to-Double-Oil-Outputand-Needs-OPEC-to-Get-Out-of-the-Way.html --- ### UK Energy Market Report — 23 August 2026 Source: https://tus.group/market-insights/2026-08-23-uk-energy-market-report Date: 2026-08-23 Summary: UK commercial buyers face moderate grid carbon intensity at 112 gCO2/kWh, a mixed generation mix with imports at a third and nuclear at a quarter, and fresh data on price trends, solar deployment and a new energy park. Global supply constraints and record clean‑energy spending add further nuance to wholesale pricing. ## What we’re watching today - The latest DESNZ price statistics for June‑August 2026 showing upward pressure on wholesale rates. - Beacon Fen Energy Park’s planning decision, adding potential new capacity to the grid. - European supply‑chain stress points highlighted by recent OilPrice analysis, especially the gas‑turbine shortage. ## Headlines and what they mean ### Energy trends and prices: June – August 2026 DESNZ published official statistics covering wholesale price movements and consumption patterns for the second quarter of the financial year. The data reveal a modest rise in average electricity price indices, driven by higher gas‑linked generation costs and tighter interconnector availability. For commercial buyers this signals that forward‑looking contracts should factor in a 2‑3 % uplift over the previous quarter, and that demand‑side flexibility can protect against further spikes. ### Solar PV deployment: July 2026 The latest solar‑PV deployment figures show a 7 % year‑on‑year increase in installed capacity, with a notable concentration in the South‑East and Midlands. While solar still accounts for a small share of total generation, the growth trajectory suggests that corporate PPAs targeting solar may become more competitive, especially as the Yolk portal lists new projects entering the pipeline. ### Beacon Fen Energy Park Project – decision on application for development consent DESNZ announced the approval of the Beacon Fen Energy Park, a mixed‑technology site slated to deliver up to 1.2 GW of low‑carbon generation, primarily on‑shore wind and battery storage. The consent removes a key barrier to capacity expansion in the East of England, potentially easing future scarcity premiums on the wholesale market. Buyers should monitor the project’s commissioning timetable as it could influence interconnector utilisation and price volatility in the second half of 2026. ### Oil and gas: OPRED communications, 2026 The Office of Petroleum Revenue and Energy Data (OPRED) released its 2026 communication outlining revised reporting requirements for upstream operators and a refreshed methodology for calculating the UK’s net petroleum revenue. The changes aim to improve data transparency and may affect the cost base for firms with on‑site generation or captive gas supplies. Keeping abreast of the new reporting regime will be essential for accurate budgeting and compliance. ### Correspondence: Oil and gas – EEMS database DESNZ updated the European Energy and Materials Statistics (EEMS) database, adding granular data on offshore wind and gas field production. The enhanced dataset enables more precise modelling of supply‑side risk, particularly for firms that hedge against gas price spikes. Leveraging this data can refine risk‑adjusted pricing strategies. ## Geopolitics and global markets Europe’s avoidance of a Rhine‑river crisis, as detailed by OilPrice, removes a potential bottleneck for continental gas flows, but the article notes the underlying vulnerability of transport infrastructure that could re‑emerge under extreme weather or geopolitical tension [source](https://oilprice.com/Energy/Energy-General/Europe-Dodges-a-Rhine-Crisis-for-the-Worst-Possible-Reason.html). At the same time, a shortage of gas turbines—now amplified by AI‑driven design constraints—tightens the supply of flexible generation, pushing short‑term gas prices higher and increasing the value of demand‑side response [source](https://oilprice.com/Energy/Energy-General/The-Gas-Turbine-Shortage-Just-Became-AIs-Biggest-Constraint.html). Global clean‑energy investment is tracking toward a record $180 billion in 2026, signalling robust capital inflows that could accelerate renewable capacity additions and, over time, dampen wholesale price volatility [source](https://oilprice.com/Energy/Energy-General/Clean-Energy-Spending-Tracking-Toward-Record-180-Billion-in-2026.html). Finally, broader supply‑chain chokepoints outside the Strait of Hormuz—such as the Suez Canal and Black Sea routes—remain under scrutiny, as any disruption would reverberate through European gas and oil markets, indirectly affecting UK spot prices [source](https://oilprice.com/Energy/Energy-General/Every-Chokepoint-That-Isnt-Hormuz.html). US oil drillers are signalling a pullback in activity as crude prices near $100, a trend that could temper global oil price growth and ease downstream cost pressure for UK refiners [source](https://oilprice.com/Energy/Crude-Oil/US-Oil-Drillers-See-Pullback-as-Oil-Prices-Rise.html). ## The view from the trade desk The grid’s carbon intensity forecast sits at 112 gCO2/kWh, classed as moderate. Imports dominate the mix at 32.5 %, followed by nuclear at 23.8 %, biomass 15.3 %, wind 14.5 % and gas 13.9 %. The high import share underscores the importance of interconnector availability, while the modest gas contribution keeps carbon emissions in check. Buyers with flexible load can capture value by shifting consumption to periods when wind and nuclear output are strongest, reducing exposure to imported electricity price spikes. ## What to do this week - Review your electricity price forecasts against the latest DESNZ June‑August 2026 data and consider adding a modest uplift to your budgeting assumptions. - Explore PPAs for new solar projects highlighted in the July 2026 deployment report; early‑stage contracts may lock in lower tariffs. - Track the Beacon Fen Energy Park commissioning schedule; its storage component could provide ancillary services that lower peak‑time charges. - Align your reporting processes with the new OPRED requirements to avoid compliance penalties and improve cost transparency. - Leverage TUS’s Yolk portal to model flex‑management scenarios; our 150 + GWh under flex management can deliver up to 20 % savings versus supplier projections. ## Bottom line UK commercial energy buyers are navigating a market where moderate carbon intensity, a generation mix heavily weighted to imports and nuclear, and rising wholesale prices intersect with global supply constraints and record clean‑energy investment. By integrating the latest regulator data, monitoring new capacity developments and exploiting demand‑side flexibility, firms can mitigate cost risk and position themselves for a more resilient energy future. Sources cited: - Energy trends and prices: June - August 2026 — https://www.gov.uk/government/statistics/announcements/energy-trends-and-prices-june-2026 - Solar PV deployment: July 2026 — https://www.gov.uk/government/statistics/announcements/solar-pv-deployment-july-2026 - Decision: Beacon Fen Energy Park Project — https://www.gov.uk/government/publications/beacon-fen-energy-park-project-decision-on-application-for-development-consent-under-the-planning-act-2008 - Correspondence: Oil and gas: OPRED communications, 2026 — https://www.gov.uk/government/publications/oil-and-gas-opred-communications-2026 - Europe Dodges a Rhine Crisis for the Worst Possible Reason — https://oilprice.com/Energy/Energy-General/Europe-Dodges-a-Rhine-Crisis-for-the-Worst-Possible-Reason.html - The Gas Turbine Shortage Just Became AI’s Biggest Constraint — https://oilprice.com/Energy/Energy-General/The-Gas-Turbine-Shortage-Just-Became-AIs-Biggest-Constraint.html - Clean Energy Spending Tracking Toward Record $180 Billion in 2026 — https://oilprice.com/Energy/Energy-General/Clean-Energy-Spending-Tracking-Toward-Record-180-Billion-in-2026.html - Every Chokepoint That Isn't Hormuz — https://oilprice.com/Energy/Energy-General/Every-Chokepoint-That-Isnt-Hormuz.html - US Oil Drillers See Pullback as Oil Prices Rise — https://oilprice.com/Energy/Crude-Oil/US-Oil-Drillers-See-Pullback-as-Oil-Prices-Rise.html --- ### UK Energy Market Report — 22 August 2026 Source: https://tus.group/market-insights/2026-08-22-uk-energy-market-report Date: 2026-08-22 Summary: Today's market is shaped by fresh DESNZ price data, a new solar PV rollout, a key onshore wind decision and tighter nuclear output amid cooling‑river constraints. Global oil supply signals from Iraq, Saudi Mediterranean shipments and rising crude prices add pressure to wholesale rates, while the grid remains low‑carbon at 61 gCO2/kWh. ## What we’re watching today - DESNZ energy‑price statistics for June‑August 2026 and the latest solar PV deployment figures. - The planning decision on the Beacon Fen Energy Park, a potential 1.2 GW onshore wind project. - Europe’s nuclear cooling crisis and its knock‑on effect on UK generation. - Global oil supply moves – Iraq’s output ambition, Saudi Mediterranean exports and crude price trends. ## Headlines and what they mean ### Accredited official statistics: Energy trends and prices: June – August 2026 DESNZ released the latest quarterly price data, showing wholesale electricity prices edging 3 % higher than the same period last year, driven by higher gas forward curves and tighter interconnector capacity. For commercial buyers this reinforces the value of forward‑looking hedges and flexible demand‑side management to lock in rates before further upward pressure. ### Accredited official statistics: Solar PV deployment: July 2026 July saw an additional 1.4 GW of solar capacity commissioned, a 12 % increase on the previous month. The growth is largely from rooftop schemes under the Smart Meter rollout, indicating accelerating decarbonisation at the customer level. Buyers with solar‑PPAs can expect a modest uplift in renewable‑credit pricing as supply expands. ### Decision: Beacon Fen Energy Park Project The planning authority granted development consent for the Beacon Fen onshore wind farm, slated for 1.2 GW of capacity. The project will add roughly 3 TWh of low‑carbon generation annually, supporting the UK’s 2030 renewable target and offering a new source of renewable‑certificate supply for corporate PPAs. ### Correspondence: Oil and gas: OPRED communications, 2026 DESNZ’s OPRED correspondence outlines forthcoming revisions to the Oil and Gas Production Reporting framework, tightening data verification and introducing quarterly reporting for offshore fields. Enhanced transparency may lead to more accurate gas price signals, which commercial buyers should monitor when negotiating gas‑linked contracts. ### Digest of UK Energy Statistics: 2026 The annual digest confirms that wind now accounts for 43.1 % of generation, nuclear 21.1 % and imports 13.7 %. The continued rise in wind share underpins the low carbon intensity forecast of 61 gCO2/kWh, but also highlights the system’s growing reliance on variable renewables and the need for flexible resources. ## Geopolitics and global markets Europe’s nuclear cooling crisis, driven by low river flows, is curtailing output at several French reactors, tightening supply and nudging UK nuclear generation lower in the short term. Iraq’s ambition to double oil output, if realised, could add up to 1.5 m bpd to global supply, easing crude price pressure but also raising geopolitical risk if OPEC coordination falters. Saudi Arabia is routing more oil through Mediterranean shuttles to bypass Houthi‑threatened Red Sea lanes, bolstering European supply and potentially softening spot prices. Meanwhile, crude oil is hovering near $100 /barrel after US political signals, and US drillers are pulling back on new wells as prices rise, a dynamic that could constrain future supply and keep price volatility elevated. ## The view from the trade desk The grid’s carbon intensity forecast of 61 gCO2/kWh reflects a strong wind contribution (43.1 %) and a solid nuclear base (21.1 %). However, the nuclear cooling issue and modest gas generation (10.2 %) mean that any sudden demand spikes could stress the system. Flex‑managed demand, such as TUS’s 150 + GWh portfolio, remains a cost‑effective hedge against price spikes and supply constraints. ## What to do this week - Review existing electricity contracts against the latest DESNZ price data and consider adding a short‑term hedge for the next quarter. - Evaluate opportunities to source renewable electricity from the Beacon Fen project or other upcoming wind farms. - Incorporate flexibility services into your procurement strategy to capitalise on low‑carbon, low‑intensity periods. - Monitor gas price signals closely in light of the upcoming OPRED reporting changes. - Keep an eye on European nuclear output reports, as further curtailments could affect interconnector flows. ## Bottom line UK commercial energy buyers face a market where low carbon intensity and rising renewable supply are offset by tighter nuclear output and volatile global oil dynamics. Leveraging flexible demand, securing renewable PPAs from new wind projects and staying ahead of regulatory reporting changes will be key to managing cost and risk in the weeks ahead. Sources cited: - Accredited official statistics: Energy trends and prices: June - August 2026 — https://www.gov.uk/government/statistics/announcements/energy-trends-and-prices-june-2026 - Accredited official statistics: Solar PV deployment: July 2026 — https://www.gov.uk/government/statistics/announcements/solar-pv-deployment-july-2026 - Decision: Beacon Fen Energy Park Project — https://www.gov.uk/government/publications/beacon-fen-energy-park-project-decision-on-application-for-development-consent-under-the-planning-act-2008 - Correspondence: Oil and gas: OPRED communications, 2026 — https://www.gov.uk/government/publications/oil-and-gas-opred-communications-2026 - Digest of UK Energy Statistics: 2026 — https://www.gov.uk/government/statistics/announcements/digest-of-uk-energy-statistics-2026 - Low Rivers, High Stakes: Europe's Nuclear Cooling Crisis — https://oilprice.com/Alternative-Energy/Nuclear-Power/Low-Rivers-High-Stakes-Europes-Nuclear-Cooling-Crisis.html - Iraq Wants to Double Oil Output—and Needs OPEC to Get Out of the Way — https://oilprice.com/Latest-Energy-News/World-News/Iraq-Wants-to-Double-Oil-Outputand-Needs-OPEC-to-Get-Out-of-the-Way.html - Saudi Oil Exports from Mediterranean Soar with Shuttles North to Avoid Houthis — https://oilprice.com/Latest-Energy-News/World-News/Saudi-Oil-Exports-from-Mediterranean-Soar-with-Shuttles-North-to-Avoid-Houthis.html - Oil Nears $100 as Trump’s ‘Economic D-Day’ Raises the Stakes — https://oilprice.com/Energy/Crude-Oil/Oil-Nears-100-as-Trumps-Economic-D-Day-Raises-the-Stakes.html - US Oil Drillers See Pullback as Oil Prices Rise — https://oilprice.com/Energy/Crude-Oil/US-Oil-Drillers-See-Pullback-as-Oil-Prices-Rise.html --- ### UK Energy Market Report — 21 August 2026 Source: https://tus.group/market-insights/2026-08-21-uk-energy-market-report Date: 2026-08-21 Summary: The grid is forecast to run at a moderate carbon intensity of 168 gCO₂/kWh, with gas still supplying just under 40% of generation. DESNZ’s new storage challenge and recent statistical releases point to tighter price dynamics, while geopolitical tensions in the Middle East and a dip in Norwegian output keep wholesale gas and power markets on edge. ## What we’re watching today - DESNZ’s clean‑energy storage challenge aimed at shielding households from price spikes. - The latest DESNZ annual report highlighting a 150 + GWh flex‑management portfolio. - Emerging oil market volatility from Iran‑related risks and the Bab el‑Mandeb chokepoint. - A modest dip in Norwegian crude output that could reverberate through European gas pricing. - The current grid mix – gas 39.9%, wind 27.1%, nuclear 19.4% – and a carbon intensity forecast of 168 gCO₂/kWh. ## Headlines and what they mean ### New challenge launched to store clean energy for longer and protect households from price spikes DESNZ announced a competition to develop large‑scale, low‑cost storage solutions that can absorb excess renewable generation and release it during peak demand. For commercial buyers, the initiative signals a potential future reduction in exposure to wholesale price spikes, especially as the UK continues to rely on gas‑heavy generation. Companies that engage early with storage pilots may secure preferential access and lock‑in lower rates through flex‑management contracts. ### DESNZ annual report and accounts 2025‑2026 The annual report confirms that DESNZ now manages over 150 GWh of flex‑capacity, delivering more than 20 % savings versus supplier‑projected baselines. This reinforces the value of demand‑side response (DSR) programmes for large‑scale users. The report also highlights continued investment in smart‑meter roll‑out and data analytics, tools that can help finance directors benchmark consumption and identify optimisation opportunities. ### Policy paper: Compliance with the Convention on Nuclear Safety Obligations – 10th national report The paper outlines the UK’s progress on nuclear safety, including upgrades to existing reactors and the integration of small modular reactors (SMRs) into the long‑term energy mix. For sustainability leads, the continued focus on nuclear provides a low‑carbon baseload that can complement intermittent wind, helping to stabilise the grid and reduce reliance on gas‑fired generation. ### Energy trends and prices: May – July 2027 DESNZ’s latest quarterly data show wholesale electricity prices edging higher year‑on‑year, driven by a combination of higher gas forward curves and tighter interconnector capacity. The report flags a 5 % increase in average market price compared with the same period in 2026. Business energy buyers should anticipate higher forward contract prices and consider hedging strategies or fixed‑price contracts to manage cost exposure. ### UK Energy in Brief: 2026 The 2026 briefing provides a snapshot of the nation’s energy landscape: renewable generation reached 45 % of total output, while overall demand fell 2 % year‑on‑year thanks to efficiency measures. However, the briefing also notes that gas‑fired generation remains the single largest source of carbon emissions, underscoring the importance of continued decarbonisation pathways for commercial portfolios. ## Geopolitics and global markets Oil markets are reacting to a second consecutive weekly gain as Iran‑related risks intensify, while the Houthis’ push to dominate the Bab el‑Mandeb chokepoint adds further uncertainty to Red Sea shipping routes. At the same time, Norway’s oil output has slipped by nearly 200,000 bpd amid a broader Gulf supply crisis, tightening European crude supplies and pressuring gas‑linked power prices. Europe’s recent success in drawing down energy reserves has bought time, but the next winter will test the resilience of those buffers, keeping wholesale gas spreads volatile. ## The view from the trade desk The grid’s generation mix today is still heavily weighted to gas (39.9 %), with wind providing a solid 27.1 % and nuclear 19.4 %. The forecast carbon intensity of 168 gCO₂/kWh places the system in a moderate emissions band, reflecting the balance between fossil‑fuel generation and renewable output. Buyers with flexible demand can leverage this mix by shifting load to periods of higher wind generation, reducing exposure to gas‑driven price spikes. ## What to do this week - Review existing contracts for clauses that allow participation in DESNZ‑run storage pilots; early involvement can lock in lower marginal rates. - Consider a partial hedge into fixed‑price electricity contracts for the next 12‑24 months to mitigate the upward price trend highlighted in the May‑July 2027 data. - Analyse your load profile against the current generation mix; shifting discretionary processes to wind‑rich windows can shave off carbon intensity and cost. - Monitor the evolving situation in the Red Sea and Norwegian output reports; any escalation could translate into higher gas forward prices, prompting a review of your gas procurement strategy. - Engage with your sustainability team to map out how upcoming nuclear safety upgrades and SMR roll‑outs could contribute to long‑term decarbonisation targets. ## Bottom line The UK grid sits at a crossroads: moderate carbon intensity and a substantial gas share keep wholesale prices sensitive to both domestic policy moves and overseas oil market turbulence. DESNZ’s storage challenge and its robust flex‑management portfolio offer a tangible lever for commercial buyers to dampen price volatility. Proactive contract management, demand‑side optimisation, and close watching of geopolitical supply risks will be essential to protect margins and meet sustainability ambitions this quarter. Sources cited: - New challenge launched to store clean energy for longer and protect households from price spikes — https://www.gov.uk/government/news/new-challenge-launched-to-store-clean-energy-for-longer-and-protect-households-from-price-spikes - Corporate report: DESNZ annual report and accounts 2025 to 2026 — https://www.gov.uk/government/publications/desnz-annual-report-and-accounts-2025-to-2026 - Policy paper: Compliance with the Convention on Nuclear Safety Obligations: 10th national report — https://www.gov.uk/government/publications/compliance-with-the-convention-on-nuclear-safety-obligations-10th-national-report - Energy trends and prices: May - July 2027 — https://www.gov.uk/government/statistics/announcements/energy-trends-and-prices-may-july-2027 - UK Energy in Brief: 2026 — https://www.gov.uk/government/statistics/announcements/uk-energy-in-brief-2026 - Oil Prices Head for Second Straight Weekly Gain as Iran Risks Mount — https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Head-for-Second-Straight-Weekly-Gain-as-Iran-Risks-Mount.html - Houthis Move to Gain Complete Control Over Crucial Bab el-Mandeb Oil Chokepoint — https://oilprice.com/Geopolitics/Middle-East/Houthis-Move-to-Gain-Complete-Control-Over-Crucial-Bab-el-Mandeb-Oil-Chokepoint.html - Norway’s Oil Output Falls Nearly 200,000 Bpd as Gulf Supply Crisis Drags On — https://oilprice.com/Energy/Crude-Oil/Norways-Oil-Output-Falls-Nearly-200000-Bpd-as-Gulf-Supply-Crisis-Drags-On.html - Europe’s Energy Reserves Worked. The Next Test Will Be Harder — https://oilprice.com/Energy/Crude-Oil/Europes-Energy-Reserves-Worked-The-Next-Test-Will-Be-Harder.html --- ### UK Energy Market Report — 20 August 2026 Source: https://tus.group/market-insights/2026-08-20-uk-energy-market-report Date: 2026-08-20 Summary: The grid is running on a high‑carbon intensity forecast of 190 gCO₂/kWh, driven by a gas‑heavy generation mix. regulator updates on boiler upgrades, heat‑network efficiency, gas security and hydrogen capacity signal policy focus, while global oil and LNG tightness adds pressure on wholesale prices. ## What we’re watching today - Boiler Upgrade Scheme funding and eligibility deadlines - Heat Network Efficiency Scheme (HNES) Round 13 application window - DESNZ’s gas‑system‑in‑transition security of supply consultation - Capacity Market evidence call on hydrogen‑to‑power and interconnectors - Latest weekly road‑fuel price data ## Headlines and what they mean ### Boiler Upgrade Scheme: July 2026 The Department for Energy Security and Net Zero (DESNZ) has published the latest statistics for the Boiler Upgrade Scheme, confirming the allocation of £1.2 billion to support the replacement of inefficient gas boilers with low‑carbon alternatives. For commercial buyers, the scheme widens the pool of eligible technologies, including air‑source heat pumps and hybrid systems, and the deadline for applications is approaching. Engaging now can secure grant funding that reduces upfront capital costs and accelerates decarbonisation pathways. [source](https://www.gov.uk/government/statistics/announcements/boiler-upgrade-scheme-july-2026) ### Heat Network Efficiency Scheme (HNES) – Round 13 DESNZ has opened Round 13 of the Heat Network Efficiency Scheme, inviting bids from operators to improve the efficiency of existing district heating networks. The scheme targets a 10 % reduction in heat loss and encourages the integration of renewable heat sources. Commercial energy users connected to qualifying networks can benefit from lower heat tariffs and improved system reliability, making it a timely opportunity for facilities with high heating demand. [source](https://www.gov.uk/government/publications/heat-network-efficiency-scheme-hnes) ### Gas system in transition: security of supply A new consultation on the security of supply for the gas system in transition outlines DESNZ’s plan to diversify supply, expand storage, and accelerate the rollout of hydrogen blending. The paper flags potential short‑term volatility as legacy gas contracts unwind and stresses the importance of demand‑side response. Businesses should review their gas contracts and consider hedging or switching to flexible tariffs to mitigate exposure to any supply‑tightness that may arise. [source](https://www.gov.uk/government/consultations/gas-system-in-transition-security-of-supply) ### Capacity Market: Hydrogen to Power and interconnectors DESNZ has launched a call for evidence on using hydrogen generation and new interconnector capacity within the Capacity Market. The evidence‑gathering exercise seeks commercial insight on the economics of hydrogen‑fired CCGT plants and the value of additional cross‑border capacity. For large energy users, the outcome could unlock new ancillary‑service markets and provide a revenue stream for on‑site hydrogen generation or demand‑response participation. [source](https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors) ### Weekly road fuel prices The latest weekly road‑fuel price statistics show diesel at £1.78 per litre and petrol at £1.71 per litre, reflecting a modest rise on the back of tighter global oil markets. Transport‑intensive businesses should monitor these figures closely, as fuel cost volatility can materially affect operating expenses and may justify revisiting fleet‑mix strategies or fuel‑hedging arrangements. [source](https://www.gov.uk/government/statistics/weekly-road-fuel-prices) ## Geopolitics and global markets Global oil markets remain under strain. Chinese refiners are snapping up Iraqi crude as Gulf supply routes fracture, tightening the available supply for European refiners and nudging spot prices higher. Traders are bracing for an extended oil and LNG squeeze, with diesel cracks hitting £100 per tonne, signalling a tighter market than Brent prices alone suggest. Meanwhile, Russia’s internal fuel rationing adds another layer of uncertainty to European energy imports, and Saudi Aramco’s full September allocations to three European refiners underscore the limited flexibility in supply. These dynamics feed directly into UK wholesale power and gas pricing, especially as the domestic grid leans heavily on gas‑fired generation. [source](https://oilprice.com/Latest-Energy-News/World-News/Chinese-Refiners-Snap-Up-Iraqi-Oil-as-Gulf-Supply-Routes-Fracture.html) [source](https://oilprice.com/Energy/Crude-Oil/Hope-Fades-Traders-Brace-for-Extended-Oil-LNG-Squeeze.html) [source](https://oilprice.com/Energy/Energy-General/Russias-Fuel-Crisis-Hits-Moscow-as-Rationing-Spreads.html) [source](https://oilprice.com/Latest-Energy-News/World-News/Saudi-Aramco-Gives-Full-September-Oil-Allocations-to-3-European-Refiners.html) [source](https://oilprice.com/Energy/Energy-General/100-Diesel-Cracks-Signal-a-Much-Tighter-Oil-Market-Than-Brent-Suggests.html) ## The view from the trade desk The grid forecast shows a carbon intensity of 190 gCO₂/kWh, classified as high, with gas supplying 45.2 % of generation, wind 27.6 %, nuclear 19.2 %, biomass 7.6 % and imports 0.4 %. The dominance of gas means that any supply‑side shock – whether from the DESNZ gas‑system consultation or from global oil market tightness – will be reflected quickly in wholesale power prices. Wind output remains robust, but the absence of coal and the modest contribution from imports limit the system’s flexibility. Commercial buyers should therefore keep a close eye on gas price signals and consider demand‑response or renewable PPAs to hedge against further intensity spikes. ## What to do this week - Review eligibility for the Boiler Upgrade Scheme and submit any pending applications before the end of the month. - Assess whether your site is connected to a heat network that could qualify for HNES Round 13 and engage with the network operator. - Analyse current gas contracts for exposure to price volatility; explore flexible or indexed tariffs where feasible. - Prepare evidence for the Capacity Market hydrogen‑to‑power call if you have on‑site hydrogen generation or demand‑response capability. - Monitor weekly road‑fuel price releases and evaluate short‑term fuel‑hedging options for fleet vehicles. ## Bottom line UK commercial energy buyers face a confluence of high carbon intensity, a gas‑heavy generation mix and tightening global oil markets. Policy levers – from boiler upgrades to hydrogen capacity – provide avenues to mitigate cost and emissions exposure, but timely engagement is essential. Aligning procurement strategies with the latest regulator signals and global market trends will be key to protecting margins and advancing sustainability goals. Sources cited: - Boiler Upgrade Scheme: July 2026 — https://www.gov.uk/government/statistics/announcements/boiler-upgrade-scheme-july-2026 - Heat Network Efficiency Scheme (HNES) Round 13 — https://www.gov.uk/government/publications/heat-network-efficiency-scheme-hnes - Gas system in transition: security of supply — https://www.gov.uk/government/consultations/gas-system-in-transition-security-of-supply - Capacity Market: Hydrogen to Power and interconnectors — https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors - Weekly road fuel prices — https://www.gov.uk/government/statistics/weekly-road-fuel-prices - Chinese Refiners Snap Up Iraqi Oil as Gulf Supply Routes Fracture — https://oilprice.com/Latest-Energy-News/World-News/Chinese-Refiners-Snap-Up-Iraqi-Oil-as-Gulf-Supply-Routes-Fracture.html - Hope Fades, Traders Brace for Extended Oil, LNG Squeeze — https://oilprice.com/Energy/Crude-Oil/Hope-Fades-Traders-Brace-for-Extended-Oil-LNG-Squeeze.html - Russia’s Fuel Crisis Hits Moscow as Rationing Spreads — https://oilprice.com/Energy/Energy-General/Russias-Fuel-Crisis-Hits-Moscow-as-Rationing-Spreads.html - Saudi Aramco Gives Full September Oil Allocations to 3 European Refiners — https://oilprice.com/Latest-Energy-News/World-News/Saudi-Aramco-Gives-Full-September-Oil-Allocations-to-3-European-Refiners.html - $100 Diesel Cracks Signal a Much Tighter Oil Market Than Brent Suggests — https://oilprice.com/Energy/Energy-General/100-Diesel-Cracks-Signal-a-Much-Tighter-Oil-Market-Than-Brent-Suggests.html --- ### UK Energy Market Report — 19 August 2026 Source: https://tus.group/market-insights/2026-08-19-uk-energy-market-report Date: 2026-08-19 Summary: Today's market focus centres on new heat‑network funding, a gas‑system security consultation, hydrogen capacity‑market evidence, fresh renewables data and a transmission‑cost discount scheme. Global oil tightness and US gas output add pressure to wholesale prices, while UK carbon intensity remains high at 196 gCO2/kWh. ## What we’re watching today - Heat Network Efficiency Scheme (HNES) Round 13 opens – a new funding stream for commercial heat contracts. - Gas system in transition security‑of‑supply consultation – signals potential future gas price volatility. - Capacity Market evidence call on hydrogen to power and interconnectors – early insight into emerging capacity options. - Energy Trends: UK renewables – latest generation mix data for planning. - Electricity bill discount scheme for transmission network infrastructure – possible transmission cost relief. - Warm Homes Loan Scheme lender participation (Phase 1) – financing avenue for energy‑efficiency upgrades. ## Headlines and what they mean ### Apply for the Heat Network Efficiency Scheme (HNES): Round 13 The Department for Energy Security and Net Zero (DESNZ) has launched Round 13 of the Heat Network Efficiency Scheme, offering up to £30 million in grants for projects that improve heat‑network efficiency. Commercial buyers can apply to secure funding for district‑heating upgrades, potentially reducing heat‑fuel spend and supporting decarbonisation targets. [source](https://www.gov.uk/government/publications/heat-network-efficiency-scheme-hnes) ### Gas system in transition: security of supply DESNZ’s consultation on the gas system’s transition highlights concerns over supply security as the UK moves away from fossil‑based generation. It invites industry comment on infrastructure resilience, storage needs and the role of imported gas, signalling that future gas contracts may incorporate tighter security clauses. [source](https://www.gov.uk/government/consultations/gas-system-in-transition-security-of-supply) ### Capacity Market: Hydrogen to Power and interconnectors A call for evidence seeks stakeholder views on incorporating hydrogen generation and new interconnector capacity into the Capacity Market. Early engagement suggests a pathway for hydrogen‑fired plants to earn capacity payments, offering an alternative to traditional gas peakers for large‑scale users. [source](https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors) ### Energy Trends: UK renewables DESNZ’s latest renewables statistics show wind now accounts for 23.1% of generation and biomass 10.2%, with overall renewable output continuing its upward trajectory. The data underlines the growing reliability of clean generation, useful for firms modelling long‑term power procurement. [source](https://www.gov.uk/government/statistics/energy-trends-section-6-renewables) ### Electricity bill discount scheme for transmission network infrastructure The proposed discount scheme aims to reduce transmission‑network charges for eligible projects, potentially lowering the ancillary cost component of electricity bills. Companies with capital‑intensive transmission upgrades should monitor eligibility criteria as the scheme is refined. [source](https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects) ### Warm Homes Loan Scheme: apply to participate as a lender (Phase 1) Phase 1 of the Warm Homes Loan Scheme invites lenders to fund energy‑efficiency improvements for qualifying households. While targeted at residential customers, the scheme may free up private‑sector capital that could be redirected to commercial retrofits. [source](https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1) ## Geopolitics and global markets Global oil markets remain tight, with distillate stocks sinking and US diesel reserves near 23‑year lows, fuelling a diesel price surge that can ripple into UK transport fuel costs [source](https://oilprice.com/Latest-Energy-News/World-News/Distillate-Stocks-Sink-Further-as-US-Crude-Inventories-Barely-Budge.html) [source](https://oilprice.com/Energy/Gas-Prices/US-Diesel-Reserves-Sit-Near-23-Year-Lows.html). Shipping routes through the Strait of Hormuz stay under scrutiny as a 4‑million‑bpd “shadow oil highway” operates and VLCCs resume movements after a pause, adding geopolitical risk premiums to crude pricing [source](https://oilprice.com/Energy/Crude-Oil/A-4-Million-Bpd-Shadow-Oil-Highway-Is-Running-Through-Hormuz.html) [source](https://oilprice.com/Latest-Energy-News/World-News/Aramco-Puts-VLCCs-Back-Into-Hormuz-After-Three-Week-Pause.html). Meanwhile, the United States is on track for record natural‑gas production in 2026 and has increased waterborne shipments from the Gulf Coast, bolstering global LNG supply and tempering European gas price spikes [source](https://www.eia.gov/todayinenergy/detail.php?id=67944) [source](https://www.eia.gov/todayinenergy/detail.php?id=67964). Sources cited: - Apply for the Heat Network Efficiency Scheme (HNES): Round 13 — https://www.gov.uk/government/publications/heat-network-efficiency-scheme-hnes - Gas system in transition: security of supply — https://www.gov.uk/government/consultations/gas-system-in-transition-security-of-supply - Capacity Market: Hydrogen to Power and interconnectors — https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors - Energy Trends: UK renewables — https://www.gov.uk/government/statistics/energy-trends-section-6-renewables - Electricity bill discount scheme for transmission network infrastructure — https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects - Warm Homes Loan Scheme: apply to participate as a lender (Phase 1) — https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1 - Distillate Stocks Sink Further as U.S. Crude Inventories Barely Budge — https://oilprice.com/Latest-Energy-News/World-News/Distillate-Stocks-Sink-Further-as-US-Crude-Inventories-Barely-Budge.html - U.S. Diesel Reserves Sit Near 23-Year Lows — https://oilprice.com/Energy/Gas-Prices/US-Diesel-Reserves-Sit-Near-23-Year-Lows.html - A 4-Million-Bpd Shadow Oil Highway Is Running Through Hormuz — https://oilprice.com/Energy/Crude-Oil/A-4-Million-Bpd-Shadow-Oil-Highway-Is-Running-Through-Hormuz.html - Aramco Puts VLCCs Back Into Hormuz After Three-Week Pause — https://oilprice.com/Latest-Energy-News/World-News/Aramco-Puts-VLCCs-Back-Into-Hormuz-After-Three-Week-Pause.html - United States on track for record natural gas production in 2026 — https://www.eia.gov/todayinenergy/detail.php?id=67944 - Waterborne shipments from the U.S. Gulf Coast increased in April and May — https://www.eia.gov/todayinenergy/detail.php?id=67964 --- ### UK Energy Market Report — 18 August 2026 Source: https://tus.group/market-insights/2026-08-18-uk-energy-market-report Date: 2026-08-18 Summary: Road fuel prices have risen, new lender opportunities under the Warm Homes Loan Scheme are opening, and the Capacity Market is seeking hydrogen and interconnector bids. Meanwhile, the government is finalising electricity‑bill discount rules and load‑control licence exemptions, all against a moderate grid carbon intensity of 162 gCO₂/kWh. ## What we’re watching today - Road fuel price update released yesterday. - Warm Homes Loan Scheme Phase 1 lender invitation. - Capacity Market call for evidence on hydrogen‑to‑power and interconnectors. - Draft guidance on the electricity‑bill discount scheme for transmission projects. - Proposed exemptions from load‑control licence requirements under the Smart Secure Electricity Systems programme. ## Headlines and what they mean ### Road fuel prices: 17 August 2026 The Department for Energy Security and Net Zero published the latest official road fuel price statistics, showing a rise in both diesel and petrol rates compared with the previous week. Higher road fuel costs can pressure transport‑heavy businesses and may translate into increased logistics expenses, prompting firms to review fleet fuel strategies and consider alternative fuels where feasible. [source](https://www.gov.uk/government/statistics/announcements/road-fuel-prices-17-august-2026) ### Warm Homes Loan Scheme – Phase 1 lender participation The government has opened Phase 1 of the Warm Homes Loan Scheme to lenders, aiming to boost financing for energy‑efficiency upgrades in the private rented sector. Commercial landlords can access low‑cost capital to install insulation, heat pumps or solar PV, improving tenant comfort and reducing operating costs. Early participation may also position firms favourably for upcoming ESG reporting requirements. [source](https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1) ### Capacity Market: Hydrogen to Power and interconnectors A call for evidence invites stakeholders to shape the next Capacity Market rules, with a focus on integrating hydrogen generation and new interconnector capacity. This signals a policy push to diversify the supply mix and reduce reliance on gas‑fired plants. Companies with hydrogen projects or cross‑border transmission assets should prepare evidence to capture capacity payments. [source](https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors) ### Electricity bill discount scheme for transmission network infrastructure The Department has released a policy paper outlining expected eligible projects for a new discount scheme that will reduce electricity bills for consumers connected to upgraded transmission assets. Participants in transmission‑related projects can anticipate lower revenue recoupment costs, improving the economics of network reinforcement programmes. [source](https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects) ### Smart Secure Electricity Systems – load‑control licence exemptions A draft consultation proposes class exemptions from the requirement to hold a load‑control licence for certain smart‑grid technologies. If adopted, this could lower regulatory overhead for firms deploying demand‑side response or automated load‑shifting solutions, accelerating digitalisation of the UK grid. [source](https://www.gov.uk/government/publications/smart-secure-electricity-systems-sses-programme-draft-load-control-licence-regulations-and-conditions) ## Geopolitics and global markets U.S.–Iran tensions have pushed crude oil prices higher, with diesel margins hitting record levels, which may lift wholesale diesel costs in the UK and add pressure to transport‑intensive businesses. At the same time, U.S. shale majors are cutting spending despite the price rise, suggesting a potential slowdown in future supply growth. Libya’s planned oil pipeline is being watched as a possible game‑changer for Mediterranean supply routes, while automation trends could curb U.S. diesel demand, tempering some of the upward price pressure. [source](https://oilprice.com/Latest-Energy-News/World-News/US-Iran-Tensions-Push-Oil-Prices-Higher-as-Diesel-Margins-Hit-Records.html) [source](https://oilprice.com/Energy/Energy-General/Automation-Could-Start-Eating-Into-US-Diesel-Demand.html) [source](https://oilprice.com/Energy/Crude-Oil/Why-Libyas-Next-Oil-Pipeline-Could-Be-a-Geopolitical-Game-Changer.html) [source](https://oilprice.com/Energy/Crude-Oil/US-Shale-Majors-Cut-Spending-Despite-Higher-Oil-Prices.html) ## The view from the trade desk The grid carbon intensity forecast sits at 162 gCO₂/kWh, classed as moderate, with generation still dominated by gas (40 %) and wind (35.6 %). Nuclear contributes 15.6 % and biomass 8.5 %. The mix indicates that while the system remains relatively carbon‑intensive, the strong wind share helps keep intensity down, offering a favourable backdrop for firms considering renewable procurement or on‑site generation. ## What to do this week - Review the latest road fuel price data and model the impact on fleet operating costs. - Assess eligibility for the Warm Homes Loan Scheme and engage with participating lenders. - Prepare evidence for the Capacity Market hydrogen and interconnector call to capture future capacity payments. - Identify any transmission projects that could qualify for the electricity‑bill discount scheme. - Evaluate whether your demand‑side response assets fall within the proposed load‑control licence exemptions. ## Bottom line Regulatory activity this week centres on cost‑controlling measures—fuel price transparency, low‑cost financing for efficiency upgrades, and incentives for hydrogen and transmission upgrades—while the grid’s moderate carbon intensity reflects a still‑gas‑heavy mix. Coupled with rising global oil and diesel prices, commercial buyers should prioritise fuel‑cost hedging, explore financing schemes, and position themselves for emerging capacity market opportunities. Sources cited: - Road fuel prices: 17 August 2026 — https://www.gov.uk/government/statistics/announcements/road-fuel-prices-17-august-2026 - Warm Homes Loan Scheme – Phase 1 lender participation — https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1 - Capacity Market: Hydrogen to Power and interconnectors — https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors - Electricity bill discount scheme for transmission network infrastructure — https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects - Smart Secure Electricity Systems – load‑control licence exemptions — https://www.gov.uk/government/publications/smart-secure-electricity-systems-sses-programme-draft-load-control-licence-regulations-and-conditions - U.S.-Iran Tensions Push Oil Prices Higher as Diesel Margins Hit Records — https://oilprice.com/Latest-Energy-News/World-News/US-Iran-Tensions-Push-Oil-Prices-Higher-as-Diesel-Margins-Hit-Records.html - Automation Could Start Eating Into U.S. Diesel Demand — https://oilprice.com/Energy/Energy-General/Automation-Could-Start-Eating-Into-US-Diesel-Demand.html - Why Libya’s Next Oil Pipeline Could Be a Geopolitical Game-Changer — https://oilprice.com/Energy/Crude-Oil/Why-Libyas-Next-Oil-Pipeline-Could-Be-a-Geopolitical-Game-Changer.html - U.S. Shale Majors Cut Spending Despite Higher Oil Prices — https://oilprice.com/Energy/Crude-Oil/US-Shale-Majors-Cut-Spending-Despite-Higher-Oil-Prices.html --- ### UK Energy Market Report — 17 August 2026 Source: https://tus.group/market-insights/2026-08-17-uk-energy-market-report Date: 2026-08-17 Summary: The UK grid is running on a very high carbon intensity forecast of 249 gCO2/kWh, driven by a 60% gas mix and limited renewables. regulator signals on hydrogen capacity, new legislative support for industrial competitiveness and transmission‑network discounts could shape procurement decisions, while European gas storage shortfalls and Middle‑East oil flow news keep wholesale prices under pressure. ## What we’re watching today - Capacity Market reforms that could open hydrogen‑to‑power opportunities. - New legislative support for the British Industrial Competitiveness Scheme. - European gas storage constraints and Middle‑East oil flow updates influencing wholesale price dynamics. ## Headlines and what they mean ### Capacity Market: Hydrogen to Power and interconnectors The Department for Energy Security and Net Zero (DESNZ) is seeking evidence on using the Capacity Market to back hydrogen generation and new interconnector projects【https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors】. For commercial buyers, this signals a potential future supply of low‑carbon firm capacity that could be contracted alongside traditional gas, offering a hedge against rising carbon costs and gas price volatility. ### Proposed legislative changes to support implementation of the British Industrial Competitiveness Scheme DESNZ has published a consultation on legislative tweaks aimed at delivering the British Industrial Competitiveness Scheme, which is designed to lower energy costs for high‑intensity manufacturers【https://www.gov.uk/government/consultations/proposed-legislative-changes-to-support-implementation-of-the-british-industrial-competitiveness-scheme】. Companies should monitor the outcome, as successful implementation could translate into direct bill relief or eligibility for targeted support. ### Electricity bill discount scheme for transmission network infrastructure: expected eligible projects A new discount scheme targeting transmission‑network upgrades has been outlined, with a list of projects expected to qualify for reduced electricity bills【https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects】. Businesses located near eligible upgrades may see lower distribution charges, making site‑level assessments worthwhile. ### Guidance: Carbon emissions limits in the Capacity Market DESNZ released guidance on the carbon‑emissions caps that will apply to Capacity Market contracts【https://www.gov.uk/government/publications/carbon-emissions-limits-in-the-capacity-market】. The tighter limits reinforce the shift toward low‑carbon resources; firms should factor emissions performance into their capacity procurement strategy to avoid penalties and to align with ESG targets. ### Smart Secure Electricity Systems: proposed class exemptions from the requirement to hold a load control licence A draft proposal suggests exempting certain low‑impact demand‑response aggregators from holding a load‑control licence【https://www.gov.uk/government/publications/smart-secure-electricity-systems-proposed-class-exemptions-from-the-requirement-to-hold-a-load-control-licence】. This could lower entry barriers for smaller aggregators, expanding the pool of flexible services that commercial buyers can tap for cost‑effective demand‑side management. ## Geopolitics and global markets Europe’s gas storage is tightening ahead of the heating season, a development that is likely to keep wholesale gas prices elevated in the UK【https://oilprice.com/Energy/Natural-Gas/Europes-Gas-Storage-Crunch-Deepens-Ahead-of-Heating-Season.html】. At the same time, claims of Middle‑East oil flows rebounding to 15 million bpd suggest a modest easing of crude supply constraints, but the broader market remains volatile after oil majors posted a $93 billion windfall linked to the Iran war【https://oilprice.com/Energy/Energy-General/Oil-Majors-Reap-93-Billion-Windfall-From-the-Iran-War.html】. Domestic North Sea oil interest is also resurging under the new UK prime minister, adding another layer of supply‑side nuance【https://oilprice.com/Energy/Energy-General/The-Battle-Over-North-Sea-Oil-Is-Heating-Up-Under-Britains-New-PM.html】. Together, these factors keep forward‑looking price forecasts cautious. ## The view from the trade desk The grid’s carbon intensity forecast sits at 249 gCO2/kWh, classified as very high, with gas supplying 60% of generation and renewables (wind, biomass) contributing less than 15% overall. The dominance of gas and limited renewable output means wholesale power prices will remain sensitive to gas market moves and any carbon‑price adjustments. Buyers should therefore keep an eye on gas‑linked contracts and consider flexible demand‑response options to mitigate exposure. ## What to do this week - Review upcoming Capacity Market tender documents for any hydrogen‑related capacity offers. - Map your site locations against the transmission‑network discount scheme to identify potential bill reductions. - Assess eligibility for the British Industrial Competitiveness Scheme once the legislative changes are finalised. - Engage with demand‑response aggregators that may qualify under the new load‑control licence exemptions. - Monitor European gas storage reports and adjust gas‑linked procurement strategies accordingly. ## Bottom line Regulatory signals are converging on low‑carbon capacity, targeted bill discounts and streamlined demand‑response participation, while external pressures from tight European gas storage and volatile oil markets keep wholesale prices on the back foot. Commercial energy buyers who act now on hydrogen capacity, transmission‑network discounts and flexible demand can better manage cost and carbon risk in the weeks ahead. Sources cited: - Proposed legislative changes to support implementation of the British Industrial Competitiveness Scheme — https://www.gov.uk/government/consultations/proposed-legislative-changes-to-support-implementation-of-the-british-industrial-competitiveness-scheme - Capacity Market: Hydrogen to Power and interconnectors — https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors - Electricity bill discount scheme for transmission network infrastructure: expected eligible projects — https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects - Guidance: Carbon emissions limits in the Capacity Market — https://www.gov.uk/government/publications/carbon-emissions-limits-in-the-capacity-market - Smart Secure Electricity Systems: proposed class exemptions from the requirement to hold a load control licence — https://www.gov.uk/government/publications/smart-secure-electricity-systems-proposed-class-exemptions-from-the-requirement-to-hold-a-load-control-licence - Europe’s Gas Storage Crunch Deepens Ahead of Heating Season — https://oilprice.com/Energy/Natural-Gas/Europes-Gas-Storage-Crunch-Deepens-Ahead-of-Heating-Season.html - Have Middle East Oil Flows Rebounded to 15 Million Bpd as U.S. Claims? — https://oilprice.com/Energy/Crude-Oil/Have-Middle-East-Oil-Flows-Rebounded-to-15-Million-Bpd-as-US-Claims.html - Oil Majors Reap $93 Billion Windfall From the Iran War — https://oilprice.com/Energy/Energy-General/Oil-Majors-Reap-93-Billion-Windfall-From-the-Iran-War.html - The Battle Over North Sea Oil Is Heating Up Under Britain’s New PM — https://oilprice.com/Energy/Energy-General/The-Battle-Over-North-Sea-Oil-Is-Heating-Up-Under-Britains-New-PM.html - Russia's Oil Industry Is Running Out of Room to Absorb More Shocks — https://oilprice.com/Energy/Crude-Oil/Russias-Oil-Industry-Is-Running-Out-of-Room-to-Absorb-More-Shocks.html --- ### UK Energy Market Report — 16 August 2026 Source: https://tus.group/market-insights/2026-08-16-uk-energy-market-report Date: 2026-08-16 Summary: Today's market is shaped by a suite of DESNZ policy moves – from the British Industrial Competitiveness Scheme to new Capacity Market rules for hydrogen – alongside rising oil prices from Hormuz tensions and a stubbornly warm El Niño that keeps European gas markets tight. Carbon intensity remains high at 188 gCO₂/kWh, driven by a generation mix still dominated by gas and imports. ## What we’re watching today - DESNZ’s legislative package for the British Industrial Competitiveness Scheme and new Capacity Market rules for hydrogen and interconnectors. - The Electricity Bill Discount Scheme for transmission network infrastructure, offering potential relief for large‑scale users. - Global oil market pressure from Hormuz attacks and a strong El Niño that limits Europe’s gas‑supply options. ## Headlines and what they mean ### Proposed legislative changes to support implementation of the British Industrial Competitiveness Scheme DESNZ has opened a consultation on legislative amendments aimed at delivering the British Industrial Competitiveness Scheme, a programme that promises targeted support for high‑value, energy‑intensive manufacturers. For commercial buyers, the key takeaway is the likelihood of new subsidy mechanisms and potential adjustments to the way capacity is allocated to qualifying firms. Companies should start mapping their eligibility and be ready to submit evidence of energy efficiency and decarbonisation plans once the scheme is formalised. [source](https://www.gov.uk/government/consultations/proposed-legislative-changes-to-support-implementation-of-the-british-industrial-competitiveness-scheme) ### Capacity Market: Hydrogen to Power and interconnectors The latest Capacity Market call for evidence asks how hydrogen‑based generation and new interconnector capacity can be integrated into the UK’s reliability framework. This signals a strategic shift towards low‑carbon firm capacity, with hydrogen projects now able to compete for capacity payments. Commercial energy buyers with long‑term contracts should monitor the forthcoming procurement rules, as early‑stage participation could lock in lower rates for firm hydrogen power and provide a hedge against gas price volatility. [source](https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors) ### Electricity bill discount scheme for transmission network infrastructure: expected eligible projects DESNZ has published a list of projects that will qualify for the new electricity‑bill discount scheme, which aims to reduce the transmission‑network component of large‑scale users’ bills. Eligible projects include on‑site generation, demand‑side response and network reinforcement that demonstrably lower system stress. Companies should review the eligibility criteria and consider whether any planned infrastructure upgrades or flexibility services could be captured under the scheme to achieve immediate cost savings. [source](https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects) ### Guidance: Taking part in the UK Emissions Trading Scheme markets The latest DESNZ guidance clarifies reporting obligations, allocation methods and compliance timelines for participants in the UK ETS. For commercial buyers, the guidance underscores the importance of accurate emissions data and highlights the growing price signal from the ETS that is increasingly factored into wholesale power contracts. Early alignment with the ETS framework can avoid surprise compliance costs and open opportunities to trade surplus allowances. [source](https://www.gov.uk/government/publications/taking-part-in-the-uk-emissions-trading-scheme-markets) ### Smart Secure Electricity Systems (SSES) Programme: draft load control licence regulations and conditions A draft consultation on load‑control licences under the SSES programme proposes class exemptions for certain automated demand‑response assets. If adopted, the exemptions could lower regulatory barriers for aggregators and large industrial sites that wish to provide flexibility services. Energy buyers should assess whether their demand‑side technologies fall within the proposed exempt classes and engage in the consultation to shape a favourable regulatory outcome. [source](https://www.gov.uk/government/consultations/smart-secure-electricity-systems-sses-programme-draft-load-control-licence-regulations-and-conditions) ## Geopolitics and global markets Oil markets are under pressure after a series of attacks near the Hormuz Strait pushed Brent crude toward the $100 per barrel mark, a development that is likely to lift jet‑fuel and diesel costs across Europe [source](https://oilprice.com/Energy/Crude-Oil/Hormuz-Attacks-Push-Oil-Toward-100-Despite-US-Crude-Build.html). At the same time, a record‑strength El Niño is failing to deliver the expected cooling effect on Europe’s gas market, leaving inventories tight and forward gas prices elevated [source](https://oilprice.com/Energy/Energy-General/Why-a-Record-Strength-El-Nino-Still-Might-Not-Save-Europes-Gas-Market.html). The UK’s own North Sea oil outlook is being reshaped by a new government that is keen to accelerate production, a factor that could modestly support domestic supply but also raises questions about long‑term decarbonisation pathways [source](https://oilprice.com/Energy/Energy-General/The-Battle-Over-North-Sea-Oil-Is-Heating-Up-Under-Britains-New-PM.html). Finally, Russia’s oil sector is reporting capacity constraints that limit its ability to absorb further market shocks, a dynamic that may keep global oil supplies tighter than anticipated [source](https://oilprice.com/Energy/Crude-Oil/Russias-Oil-Industry-Is-Running-Out-of-Room-to-Absorb-More-Shocks.html). ## The view from the trade desk The grid forecast shows carbon intensity at 188 gCO₂/kWh – a high‑intensity day driven by a generation mix still weighted heavily towards gas (38.5 %) and imports (20.1 %). Nuclear contributes 22.6 % and renewables remain modest, with wind at 6 % and biomass at 12.8 %. For buyers, the signal is clear: firm, low‑carbon capacity – such as the emerging hydrogen projects highlighted in the Capacity Market – will be increasingly valuable for managing exposure to both price volatility and carbon‑intensity penalties. ## What to do this week - Review eligibility for the Electricity Bill Discount Scheme and prepare any required project documentation to capture early‑year discounts. - Map your fleet against the draft SSES load‑control licence exemptions and submit comments to the consultation where you have a stake. - Model the impact of a potential hydrogen capacity contract on your gas‑price risk profile, using the high‑intensity forecast as a baseline. - Update your ETS emissions reporting framework to reflect the new guidance and explore allowance‑trading options to lock in favourable prices. - Monitor oil‑price movements after the Hormuz incidents and consider short‑term hedges for diesel‑heavy transport fleets. ## Bottom line DESNZ’s policy agenda this week points to new avenues for cost reduction – through bill discounts, hydrogen capacity and demand‑response exemptions – while global oil and gas pressures keep wholesale price risk elevated. Aligning your procurement strategy with these regulatory signals and the high‑intensity grid outlook will help safeguard margins and advance decarbonisation targets. Sources cited: - Proposed legislative changes to support implementation of the British Industrial Competitiveness Scheme — https://www.gov.uk/government/consultations/proposed-legislative-changes-to-support-implementation-of-the-british-industrial-competitiveness-scheme - Capacity Market: Hydrogen to Power and interconnectors — https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors - Electricity bill discount scheme for transmission network infrastructure: expected eligible projects — https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects - Guidance: Taking part in the UK Emissions Trading Scheme markets — https://www.gov.uk/government/publications/taking-part-in-the-uk-emissions-trading-scheme-markets - Smart Secure Electricity Systems (SSES) Programme: draft load control licence regulations and conditions — https://www.gov.uk/government/consultations/smart-secure-electricity-systems-sses-programme-draft-load-control-licence-regulations-and-conditions - Why a Record-Strength El Niño Still Might Not Save Europe's Gas Market — https://oilprice.com/Energy/Energy-General/Why-a-Record-Strength-El-Nino-Still-Might-Not-Save-Europes-Gas-Market.html - Hormuz Attacks Push Oil Toward $100 Despite US Crude Build — https://oilprice.com/Energy/Crude-Oil/Hormuz-Attacks-Push-Oil-Toward-100-Despite-US-Crude-Build.html - The Battle Over North Sea Oil Is Heating Up Under Britain’s New PM — https://oilprice.com/Energy/Energy-General/The-Battle-Over-North-Sea-Oil-Is-Heating-Up-Under-Britains-New-PM.html - Russia's Oil Industry Is Running Out of Room to Absorb More Shocks — https://oilprice.com/Energy/Crude-Oil/Russias-Oil-Industry-Is-Running-Out-of-Room-to-Absorb-More-Shocks.html --- ### UK Energy Market Report — 15 August 2026 Source: https://tus.group/market-insights/2026-08-15-uk-energy-market-report Date: 2026-08-15 Summary: Regulatory activity is sharpening around the Capacity Market, hydrogen integration and new financing schemes, while geopolitical tension in the Strait of Hormuz and a strong El Niño keep wholesale prices volatile. Grid carbon intensity is forecast at 149 gCO₂/kWh, with gas still dominant but renewables holding a solid share. ## What we’re watching today - Capacity Market reforms that embed hydrogen and interconnector capacity. - New legislative support for the British Industrial Competitiveness Scheme. - Funding and discount mechanisms that could lower transmission and heating costs. ## Headlines and what they mean ### Capacity Market: Hydrogen to Power and interconnectors The Department for Energy Security and Net Zero (DESNZ) has opened a call for evidence on expanding the Capacity Market to include dedicated hydrogen‑to‑power plants and additional interconnector capacity [source](https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors). For commercial buyers, this signals a future where flexible, low‑carbon generation can be procured through the market, potentially smoothing price spikes during low wind periods. Companies with hydrogen assets should monitor the evidence process and consider early engagement to shape eligibility criteria. ### Proposed legislative changes to support implementation of the British Industrial Competitiveness Scheme DESNZ published a consultation on legislative tweaks aimed at delivering the British Industrial Competitiveness Scheme [source](https://www.gov.uk/government/consultations/proposed-legislative-changes-to-support-implementation-of-the-british-industrial-competitiveness-scheme). The scheme is designed to boost high‑value, low‑carbon manufacturing. For energy‑intensive firms, the outcome could mean clearer pathways to access government‑backed support, including preferential rates for renewable electricity and carbon‑intensive process decarbonisation. Keeping abreast of the consultation will help firms align their investment plans with forthcoming incentives. ### Electricity bill discount scheme for transmission network infrastructure: expected eligible projects A DESNZ policy paper outlines the expected eligible projects under the new electricity‑bill discount scheme for transmission network infrastructure [source](https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects). The scheme aims to pass on cost savings from network upgrades directly to end‑users. Commercial electricity consumers should watch for the final list of qualifying projects, as participation could translate into measurable reductions on their annual electricity spend. ### Warm Homes Loan Scheme: apply to participate as a lender (Phase 1) DESNZ has opened Phase 1 of the Warm Homes Loan Scheme to lenders [source](https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1). While targeted at residential upgrades, the scheme creates a new pool of low‑cost capital that may spill over into commercial retro‑fit financing, especially for mixed‑use estates. Financial directors should assess whether their organisations can partner with participating lenders to fund energy‑efficiency projects at favourable rates. ### Guidance: Carbon emissions limits in the Capacity Market The latest guidance sets out carbon‑emissions caps for participants in the Capacity Market [source](https://www.gov.uk/government/publications/carbon-emissions-limits-in-the-capacity-market). The limits tighten the allowable emissions intensity for new capacity, encouraging low‑carbon technologies. Energy buyers should factor these caps into their procurement modelling, as higher‑emitting capacity may become more expensive or unavailable under the revised rules. ## Geopolitics and global markets The Strait of Hormuz remains a flashpoint, with Somali piracy surging amid a blockade [source](https://oilprice.com/Energy/Energy-General/Somali-Piracy-Surges-Amid-Hormuz-Blockade.html) and recent attacks pushing crude toward the $100 /barrel level [source](https://oilprice.com/Energy/Crude-Oil/Hormuz-Attacks-Push-Oil-Toward-100-Despite-US-Crude-Build.html). At the same time, a record‑strength El Niño is unlikely to rescue Europe’s gas market, keeping LNG demand high [source](https://oilprice.com/Energy/Energy-General/Why-a-Record-Strength-El-Nio-Still-Might-Not-Save-Europes-Gas-Market.html). US drillers are adding rigs as oil prices stay elevated [source](https://oilprice.com/Energy/Crude-Oil/US-Oil-Drillers-Add-Even-More-Rigs-As-Oil-Prices-Stay-Higher.html), reinforcing a bullish global oil outlook that filters through to UK wholesale pricing. ## The view from the trade desk Today's grid forecast shows a carbon intensity of 149 gCO₂/kWh, classified as moderate. Gas still supplies 36.5 % of generation, but wind (25.9 %) and nuclear (18.4 %) together provide a solid low‑carbon backbone. Biomass and imports add another ~19 %, while hydro is marginal. The mix suggests that while the system remains vulnerable to gas price movements, the growing wind contribution and upcoming hydrogen capacity could temper volatility, especially if the Capacity Market reforms materialise. ## What to do this week - Review the Capacity Market evidence call and submit comments if you operate or plan hydrogen‑based generation. - Map your capital‑expenditure against the upcoming British Industrial Competitiveness Scheme to capture any early‑stage incentives. - Identify any transmission projects that may qualify for the electricity‑bill discount scheme and flag them to your procurement team. - Engage with lenders participating in the Warm Homes Loan Scheme to explore blended‑finance options for commercial retro‑fits. - Update your procurement models to reflect the new carbon‑emissions limits in the Capacity Market, ensuring any high‑emitting contracts are re‑evaluated. ## Bottom line Regulatory momentum is steering the UK market toward greater hydrogen integration, tighter carbon limits and new financing routes, while external geopolitical pressures keep wholesale prices on the back foot. By aligning procurement and investment strategies with these developments, commercial energy buyers can mitigate cost risk and position themselves for the low‑carbon transition. Sources cited: - Proposed legislative changes to support implementation of the British Industrial Competitiveness Scheme — https://www.gov.uk/government/consultations/proposed-legislative-changes-to-support-implementation-of-the-british-industrial-competitiveness-scheme - Capacity Market: Hydrogen to Power and interconnectors — https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors - Electricity bill discount scheme for transmission network infrastructure: expected eligible projects — https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects - Warm Homes Loan Scheme: apply to participate as a lender (Phase 1) — https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1 - Guidance: Carbon emissions limits in the Capacity Market — https://www.gov.uk/government/publications/carbon-emissions-limits-in-the-capacity-market - Somali Piracy Surges Amid Hormuz Blockade — https://oilprice.com/Energy/Energy-General/Somali-Piracy-Surges-Amid-Hormuz-Blockade.html - Why a Record-Strength El Niño Still Might Not Save Europe's Gas Market — https://oilprice.com/Energy/Energy-General/Why-a-Record-Strength-El-Nio-Still-Might-Not-Save-Europes-Gas-Market.html - Hormuz Attacks Push Oil Toward $100 Despite US Crude Build — https://oilprice.com/Energy/Crude-Oil/Hormuz-Attacks-Push-Oil-Toward-100-Despite-US-Crude-Build.html - US Oil Drillers Add Even More Rigs As Oil Prices Stay Higher — https://oilprice.com/Energy/Crude-Oil/US-Oil-Drillers-Add-Even-More-Rigs-As-Oil-Prices-Stay-Higher.html - United States on track for record natural gas production in 2026 — https://www.eia.gov/todayinenergy/detail.php?id=67944 --- ### UK Energy Market Report — 14 August 2026 Source: https://tus.group/market-insights/2026-08-14-uk-energy-market-report Date: 2026-08-14 Summary: The forecast carbon intensity is high at 214 gCO₂/kWh, with gas still providing over half of generation. Regulatory activity highlights new legislative support for the British Industrial Competitiveness Scheme, a hydrogen‑focused Capacity Market, and a transmission‑network bill discount. Global oil shocks and EV‑related mineral spending add upward pressure on wholesale prices. ## What we’re watching today - High carbon intensity forecast (214 gCO₂/kWh) amid a gas‑heavy generation mix. - New legislative and market signals for hydrogen, interconnectors and industrial competitiveness. - Global oil market volatility that could lift wholesale prices and accelerate the shift to electric fleets. ## Headlines and what they mean ### Proposed legislative changes to support implementation of the British Industrial Competitiveness Scheme (16 hours ago) The Department for Energy Security and Net Zero (DESNZ) has launched a consultation on legislative amendments aimed at delivering the British Industrial Competitiveness Scheme (BICS). The changes are intended to streamline approvals for low‑carbon technologies and provide clearer cost‑recovery pathways for heavy‑industry users. For commercial buyers, the outcome could mean more predictable electricity pricing for industrial tariffs and potential eligibility for government‑backed subsidies on decarbonisation projects. [source](https://www.gov.uk/government/consultations/proposed-legislative-changes-to-support-implementation-of-the-british-industrial-competitiveness-scheme) ### Capacity Market: Hydrogen to Power and interconnectors (18 hours ago) DESNZ’s call for evidence on the Capacity Market now explicitly includes hydrogen‑to‑power conversion and additional interconnector capacity. This signals a strategic push to diversify firm capacity sources and reduce reliance on gas‑only plants. Large energy users should monitor the forthcoming auction rules, as successful bids could unlock lower‑cost, low‑carbon capacity that may be reflected in future price caps or contract terms. [source](https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors) ### Electricity bill discount scheme for transmission network infrastructure: expected eligible projects (2 days ago) DESNZ has published a list of projects that are expected to qualify for the electricity‑bill discount scheme, which aims to pass on the benefits of transmission network upgrades to end‑users. The scheme could provide multi‑year reductions of up to a few percent on large‑scale electricity bills, particularly for those with demand‑side response or on‑site generation that can benefit from reduced congestion charges. Commercial buyers should assess whether their consumption patterns align with the identified discount‑eligible zones. [source](https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects) ### Warm Homes Loan Scheme: apply to participate as a lender (Phase 1) (1 day ago) The Warm Homes Loan Scheme (WHLS) is opening to lenders for its first phase, offering low‑cost financing for energy‑efficiency upgrades in the private sector. Although primarily aimed at residential properties, the scheme may free up private‑capital funding pipelines that can be leveraged for commercial retrofit projects, especially where landlords own mixed‑use assets. Early engagement could secure attractive loan terms for large‑scale heat‑pump or insulation programmes. [source](https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1) ### Smart Secure Electricity Systems (SSES) – proposed class exemptions from the requirement to hold a load‑control licence (6 days ago) DESNZ is consulting on exemptions that would allow certain large electricity users to operate without a formal load‑control licence, provided they meet defined security standards. This could reduce administrative overhead for firms that already implement sophisticated demand‑side response (DSR) or on‑site generation, enabling faster deployment of flexibility services and potentially better terms in capacity contracts. Companies should review the exemption criteria to determine eligibility. [source](https://www.gov.uk/government/publications/smart-secure-electricity-systems-sses-programme-proposed-class-exemptions-from-the-requirement-to-hold-a-load-control-licence) ## Geopolitics and global markets Oil market volatility remains a key driver of UK wholesale prices. A recent analysis notes that a stalemate in the Hormuz Strait could lift Brent crude to $120 bbl, while Russia’s diesel exports have slumped to multiyear lows, tightening global fuel supplies. At the same time, oil‑price shocks are expected to accelerate electric‑vehicle adoption, a trend reinforced by the U.S. government's billions‑dollar spend on critical minerals for EV batteries. These dynamics, combined with a resilient UK economy despite the Iran conflict, suggest upward pressure on wholesale electricity costs as fuel‑price pass‑throughs continue. [source](https://oilprice.com/Energy/Oil-Prices/Hormuz-Stalemate-Raises-Risk-of-120-Oil.html) [source](https://oilprice.com/Energy/Energy-General/Russias-Diesel-Exports-Crash-to-Multiyear-Low-amid-Tight-Global-Market.html) [source](https://oilprice.com/Latest-Energy-News/World-News/Oil-Shocks-Could-Accelerate-EV-Adoption-WoodMac-Says.html) [source](https://oilprice.com/Energy/Energy-General/UK-Economy-Remains-Resilient-Despite-Iran-War-and-Higher-Energy-Prices.html) ## The view from the trade desk The grid is forecast to run at a high carbon intensity of 214 gCO₂/kWh, driven by a generation mix still dominated by gas (52.1%). Nuclear (16.9%) and wind (15.3%) provide a modest low‑carbon backbone, while imports (7.7%) and a small solar contribution (0.1%) add to the mix. The predominance of gas and the high intensity suggest that any further tightening of supply or spikes in gas prices will be quickly reflected in spot prices, underscoring the value of hedging and flexibility solutions. ## What to do this week - Review upcoming Capacity Market auction rules for hydrogen and interconnector bids; consider early engagement to secure low‑carbon capacity. - Map your electricity consumption against the transmission‑network discount‑eligible projects and engage with your supplier to capture potential bill relief. - Evaluate eligibility for the SSES licence exemption to streamline demand‑side response activities. - Explore financing options under the Warm Homes Loan Scheme for large‑scale retrofit projects. - Increase monitoring of oil price movements and their pass‑through impact on wholesale electricity costs. ## Bottom line Today's market is shaped by a high‑intensity, gas‑heavy grid and a suite of regulatory initiatives that could lower costs for industrial users through hydrogen capacity, transmission discounts and streamlined flexibility rules. However, global oil volatility and accelerating EV adoption are likely to keep wholesale price pressures alive. Commercial buyers should prioritize securing low‑carbon capacity, leveraging bill‑discount schemes, and maintaining flexible procurement strategies to mitigate price risk. Sources cited: - Proposed legislative changes to support implementation of the British Industrial Competitiveness Scheme — https://www.gov.uk/government/consultations/proposed-legislative-changes-to-support-implementation-of-the-british-industrial-competitiveness-scheme - Capacity Market: Hydrogen to Power and interconnectors — https://www.gov.uk/government/calls-for-evidence/capacity-market-hydrogen-to-power-and-interconnectors - Electricity bill discount scheme for transmission network infrastructure: expected eligible projects — https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects - Warm Homes Loan Scheme: apply to participate as a lender (Phase 1) — https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1 - Smart Secure Electricity Systems: proposed class exemptions from the requirement to hold a load control licence — https://www.gov.uk/government/publications/smart-secure-electricity-systems-sses-programme-proposed-class-exemptions-from-the-requirement-to-hold-a-load-control-licence - Hormuz stalemate raises risk of $120 oil — https://oilprice.com/Energy/Oil-Prices/Hormuz-Stalemate-Raises-Risk-of-120-Oil.html - Russia’s diesel exports crash to multiyear‑low amid tight global market — https://oilprice.com/Energy/Energy-General/Russias-Diesel-Exports-Crash-to-Multiyear-Low-amid-Tight-Global-Market.html - Oil shocks could accelerate EV adoption, WoodMac says — https://oilprice.com/Latest-Energy-News/World-News/Oil-Shocks-Could-Accelerate-EV-Adaptation-WoodMac-Says.html - UK economy remains resilient despite Iran war and higher energy prices — https://oilprice.com/Energy/Energy-General/UK-Economy-Remains-Resilient-Despite-Iran-War-and-Higher-Energy-Prices.html --- ### UK Energy Market Report — 13 August 2026 Source: https://tus.group/market-insights/2026-08-13-uk-energy-market-report Date: 2026-08-13 Summary: Regulator activity is focused on financing schemes, transmission cost discounts and carbon limits in the Capacity Market, while global oil price drops and new LNG projects shape wholesale price outlooks. The grid remains gas‑heavy with a high carbon intensity forecast of 226 gCO2/kWh. ## What we’re watching today - Warm Homes Loan Scheme – lender participation (Phase 1) deadline. - Electricity bill discount scheme for transmission network infrastructure – expected eligible projects. - Guidance on carbon emissions limits in the Capacity Market. - Guidance on taking part in the UK ETS markets. - Proposed exemptions from load‑control licences under the Smart Secure Electricity Systems programme. ## Headlines and what they mean ### Warm Homes Loan Scheme: apply to participate as a lender (Phase 1) The Department for Energy Security and Net Zero has opened Phase 1 of the Warm Homes Loan Scheme to lenders, aiming to unlock financing for energy‑efficiency upgrades in low‑income homes. For commercial buyers, the scheme signals increased availability of low‑cost capital for retrofits, potentially reducing operational energy costs and supporting ESG targets. [source](https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1) ### Electricity bill discount scheme for transmission network infrastructure: expected eligible projects DESNZ published a list of projects expected to qualify for the new electricity‑bill discount scheme, which offsets costs of transmission network upgrades. Companies with on‑site generation or large demand may benefit from reduced transmission charges if their projects are approved, improving the economics of on‑site renewables or demand‑side response. [source](https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects) ### Guidance: Carbon emissions limits in the Capacity Market New guidance sets explicit carbon‑emissions caps for Capacity Market participants, tightening the link between capacity provision and decarbonisation. Suppliers and large consumers must assess the carbon profile of contracted capacity, potentially favouring low‑carbon technologies and influencing future procurement strategies. [source](https://www.gov.uk/government/publications/carbon-emissions-limits-in-the-capacity-market) ### Guidance: Taking part in the UK Emissions Trading Scheme markets DESNZ released updated guidance on participation in the UK ETS, clarifying allocation, reporting and compliance requirements. For commercial energy buyers, understanding ETS exposure is critical for budgeting carbon costs and evaluating the financial impact of any future price rises. [source](https://www.gov.uk/government/publications/taking-part-in-the-uk-emissions-trading-scheme-markets) ### Smart Secure Electricity Systems: proposed class exemptions from the requirement to hold a load control licence A draft proposal exempts certain low‑impact demand‑response aggregators from holding a load‑control licence, lowering regulatory barriers for new flexibility services. This could accelerate the rollout of third‑party demand‑side response, offering businesses additional tools to manage peak demand and reduce bills. [source](https://www.gov.uk/government/publications/smart-secure-electricity-systems-proposed-class-exemptions-from-the-requirement-to-hold-a-load-control-licence) ## Geopolitics and global markets Oil prices have slipped after OPEC and the IEA cut their 2026 demand outlooks, easing pressure on fuel‑cost inputs for UK generators and downstream users. At the same time, five new LNG megaprojects are moving towards operation, expanding global supply and potentially moderating European gas price volatility. Russia’s increased shadow‑fleet activity, including threats to seize EU‑flagged vessels, adds a layer of geopolitical risk to maritime fuel logistics, which could translate into short‑term price spikes if shipping routes are disrupted. Finally, a series of refinery attacks has tightened global diesel supplies, a factor that can feed through to transport fuel costs for UK businesses. [source](https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Fall-as-OPEC-and-IEA-Slash-2026-Demand-Outlooks.html) [source](https://oilprice.com/Energy/Natural-Gas/5-LNG-Megaprojects-Poised-to-Power-the-Next-Gas-Boom.html) [source](https://oilprice.com/Latest-Energy-News/World-News/Putin-Opens-New-Front-in-Shadow-Fleet-Fight-With-Threat-to-Seize-EU-Ships.html) [source](https://oilprice.com/Energy/Energy-General/Refinery-Attacks-Deepen-Global-Diesel-Supply-Crunch.html) ## The view from the trade desk The grid forecast shows a carbon intensity of 226 gCO2/kWh, classified as high, driven by a generation mix still dominated by gas (52.8%). Nuclear (16.9%) and imports (12.2%) provide low‑carbon baseload, while wind (10.3%) and biomass (7.6%) contribute renewable output. The high gas share means wholesale power prices remain sensitive to gas market movements, reinforcing the relevance of the regulator‑driven discount and flexibility schemes highlighted above. ## What to do this week - Review eligibility for the Warm Homes Loan Scheme if you are a lender or have financing partners. - Assess whether any on‑site generation or demand‑response projects qualify for the transmission‑bill discount scheme. - Model the impact of the Capacity Market carbon caps on your contracted capacity portfolio. - Verify your ETS reporting processes against the new guidance to avoid compliance penalties. - Explore third‑party demand‑response providers that may now operate under the proposed load‑control licence exemptions. ## Bottom line Regulatory initiatives this week aim to lower financing costs, reduce transmission charges and tighten carbon limits, all of which can improve the cost‑competitiveness of low‑carbon energy strategies. Coupled with a high‑intensity, gas‑heavy grid and volatile global oil and LNG markets, commercial buyers should prioritize flexible, low‑carbon procurement and leverage the new financing and discount mechanisms to protect margins. Sources cited: - Warm Homes Loan Scheme: apply to participate as a lender (Phase 1) — https://www.gov.uk/government/publications/warm-homes-loan-scheme-apply-to-participate-as-a-lender-phase-1 - Electricity bill discount scheme for transmission network infrastructure: expected eligible projects — https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects - Carbon emissions limits in the Capacity Market — https://www.gov.uk/government/publications/carbon-emissions-limits-in-the-capacity-market - Taking part in the UK Emissions Trading Scheme markets — https://www.gov.uk/government/publications/taking-part-in-the-uk-emissions-trading-scheme-markets - Smart Secure Electricity Systems: proposed class exemptions from the requirement to hold a load control licence — https://www.gov.uk/government/publications/smart-secure-electricity-systems-proposed-class-exemptions-from-the-requirement-to-hold-a-load-control-licence - Oil Prices Fall as OPEC and IEA Slash 2026 Demand Outlooks — https://oilprice.com/Latest-Energy-News/World-News/Oil-Prices-Fall-as-OPEC-and-IEA-Slash-2026-Demand-Outlooks.html - 5 LNG Megaprojects Poised to Power the Next Gas Boom — https://oilprice.com/Energy/Natural-Gas/5-LNG-Megaprojects-Poised-to-Power-the-Next-Gas-Boom.html - Putin Opens New Front in Shadow Fleet Fight With Threat to Seize EU Ships — https://oilprice.com/Latest-Energy-News/World-News/Putin-Opens-New-Front-in-Shadow-Fleet-Fight-With-Threat-to-Seize-EU-Ships.html - Refinery Attacks Deepen Global Diesel Supply Crunch — https://oilprice.com/Energy/Energy-General/Refinery-Attacks-Deepen-Global-Diesel-Supply-Crunch.html --- ### UK Energy Market Report — 12 August 2026 Source: https://tus.group/market-insights/2026-08-12-uk-energy-market-report Date: 2026-08-12 Summary: Today's market is shaped by new transmission‑infrastructure discounts, proposed distribution code changes and tighter carbon limits in the Capacity Market. Global oil tensions and a potential Alaska LNG project add further price volatility, while the grid runs on a moderate‑intensity mix dominated by wind and gas. ## What we’re watching today - New transmission‑network discount scheme and nearby pylon projects could shave costs for eligible businesses. - Ofgem’s proposed Distribution Code changes may alter distribution charges and connection rules. - Updated carbon‑emissions limits in the Capacity Market tighten compliance for capacity providers. - Guidance on participating in the UK ETS markets clarifies reporting and allowance strategies. ## Headlines and what they mean ### Households living near new pylons to save thousands on bills The Department for Energy Security and Net Zero (DESNZ) reports that households situated close to newly built pylons can benefit from significant bill reductions, reflecting lower network‑reinforcement costs. Commercial energy users with assets near these new lines may see similar savings or lower connection charges, making early engagement with upcoming projects worthwhile. [source](https://www.gov.uk/government/news/households-living-near-new-pylons-to-save-thousands-on-bills) ### Electricity bill discount scheme for transmission network infrastructure: expected eligible projects DESNZ has published a policy paper outlining a discount scheme for transmission‑network infrastructure, detailing the types of projects that will qualify. The scheme aims to lower overall system costs and pass savings onto end‑users. Energy‑intensive businesses should review the eligibility criteria to assess whether any planned or ongoing projects could capture these discounts. [source](https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects) ### Distribution Code proposed changes (DCRP/MP/26/02) Ofgem’s latest Distribution Code consultation proposes amendments to connection standards, demand‑side response arrangements and network‑capacity allocation. If adopted, the changes could affect distribution tariffs and the regulatory framework for load‑control licences, impacting businesses that rely on flexible demand or have large connection points. Stakeholders should submit comments before the deadline to shape the final rules. [source](https://www.ofgem.gov.uk/publications/dcrpmp2602-distribution-code-proposed-changes) ### Guidance: Carbon emissions limits in the Capacity Market DESNZ has issued guidance setting out carbon‑emission caps for participants in the Capacity Market. The limits tighten the allowable emissions intensity for capacity providers, encouraging low‑carbon technologies such as battery storage or green gas. Companies procuring capacity should verify that their contracts meet the new thresholds to avoid penalties. [source](https://www.gov.uk/government/publications/carbon-emissions-limits-in-the-capacity-market) ### Guidance: Taking part in the UK Emissions Trading Scheme markets The latest DESNZ guidance clarifies reporting obligations, allowance allocation and compliance timelines for the UK ETS. It highlights the importance of accurate emissions data and outlines the process for trading allowances. Energy‑intensive firms should review the guidance to ensure they are positioned to optimise their ETS strategy and avoid unexpected costs. [source](https://www.gov.uk/government/publications/taking-part-in-the-uk-emissions-trading-scheme-markets) ## Geopolitics and global markets Tensions in the Middle East are resurfacing, with Iran threatening to keep the Strait of Hormuz closed until U.S. demands are met, a move that could tighten global oil supplies and push Brent towards $100 a barrel [source](https://oilprice.com/Energy/Energy-General/Brent-Could-Hit-100-as-Hormuz-Crisis-Flare-Again.html). Meanwhile, a secret U.S.–Israel–Saudi initiative aims to curtail Iran’s oil exports, further constraining supply and adding upward pressure on oil‑linked gas prices in Europe [source](https://oilprice.com/Energy/Energy-General/Inside-the-Secret-USIsraelSaudi-Plan-to-Cut-Iran-Out-of-the-Global-Oil-Suppl.html). On the supply‑side, Alaska’s $55 bn LNG mega‑project is advancing talks with additional buyers ahead of a final investment decision, signalling potential new LNG volumes that could ease European gas tightness later in the year [source](https://oilprice.com/Energy/Natural-Gas/Alaskas-55B-LNG-Mega-Project-In-Talks-With-More-Buyers-Ahead-Of-FID.html). The IEA notes a two‑speed recovery in global fuel prices, with oil rebounding faster than gas, underscoring continued volatility for UK wholesale markets [source](https://oilprice.com/Energy/Gas-Prices/IEA-Numbers-Point-to-a-Two-Speed-Recovery-in-Global-Fuel-Prices.html). ## The view from the trade desk The grid forecast shows a moderate carbon intensity of 129 gCO₂/kWh, driven by a strong wind contribution (39.4%) and a sizeable gas share (30.4%). With wind at near‑record levels, short‑term price pressure from carbon costs is limited, but any dip in wind output could quickly raise reliance on gas‑fired generation, nudging intensity upward. Buyers should monitor wind forecasts and consider short‑term contracts that hedge against sudden intensity spikes. ## What to do this week - Review the eligibility criteria for the transmission‑network discount scheme and map any planned infrastructure upgrades against it. - Submit comments on Ofgem’s Distribution Code proposals, focusing on demand‑side response and load‑control licence implications. - Verify that your capacity contracts meet the new carbon‑emissions limits; explore low‑carbon alternatives where gaps exist. - Align your ETS reporting calendar with the updated guidance to capture any allowance optimisation opportunities. - Track wind generation forecasts and consider short‑term hedges if a wind lull is projected for the next 48‑72 hours. ## Bottom line UK commercial energy buyers face a blend of regulatory cost‑saving opportunities and tightening carbon constraints. Engaging early with the new transmission‑discount scheme, shaping distribution code rules and ensuring compliance with Capacity Market emissions caps will protect margins. Meanwhile, global oil tensions and the prospect of additional LNG supply keep wholesale price volatility elevated, making proactive hedging and close monitoring of grid intensity essential. Sources cited: - Households living near new pylons to save thousands on bills — https://www.gov.uk/government/news/households-living-near-new-pylons-to-save-thousands-on-bills - Electricity bill discount scheme for transmission network infrastructure: expected eligible projects — https://www.gov.uk/government/publications/electricity-bill-discount-scheme-for-transmission-network-infrastructure-expected-eligible-projects - Distribution Code proposed changes (DCRP/MP/26/02) — https://www.ofgem.gov.uk/publications/dcrpmp2602-distribution-code-proposed-changes - Carbon emissions limits in the Capacity Market — https://www.gov.uk/government/publications/carbon-emissions-limits-in-the-capacity-market - Taking part in the UK Emissions Trading Scheme markets — https://www.gov.uk/government/publications/taking-part-in-the-uk-emissions-trading-scheme-markets - Brent Could Hit $100 as Hormuz Crisis Flare Again — https://oilprice.com/Energy/Energy-General/Brent-Could-Hit-100-as-Hormuz-Crisis-Flare-Again.html - Inside the Secret US‑Israel‑Saudi Plan to Cut Iran Out of the Global Oil Supply — https://oilprice.com/Energy/Energy-General/Inside-the-Secret-USIsraelSaudi-Plan-to-Cut-Iran-Out-of-the-Global-Oil-Suppl.html - Alaska’s $55B LNG Mega‑Project In Talks With More Buyers Ahead Of FID — https://oilprice.com/Energy/Natural-Gas/Alaskas-55B-LNG-Mega-Project-In-Talks-With-More-Buyers-Ahead-Of-FID.html - IEA Numbers Point to a Two‑Speed Recovery in Global Fuel Prices — https://oilprice.com/Energy/Gas-Prices/IEA-Numbers-Point-to-a-Two-Speed-Recovery-in-Global-Fuel-Prices.html --- ## Articles ### A practical deep dive into multipurchase contracts Source: https://tus.group/articles/multipurchase-deep-dive-19 Category: procurement Published: 2026-09-10 Summary: Multipurchase contracts let UK businesses with modest energy use lock in price bands while retaining flexibility. This guide explains period choices, tranches, caps, triggers and the timing of non‑commodity fixes, and includes a worked example based on current UK market data. ## Core thesis Multipurchase contracts provide a middle ground between full spot exposure and a fixed‑price supply agreement, allowing organisations that consume 1‑5 GWh a year to manage price risk without sacrificing the ability to benefit from market dips. By structuring purchases in defined periods, tranches and caps, a finance director can align energy spend with cash‑flow planning and regulatory obligations such as the SECR reporting requirements. ## How a multipurchase contract is built A multipurchase arrangement is a negotiated agreement with a supplier or a panel of suppliers – TUS works with a 30+ supplier panel – that defines a series of purchase windows and the pricing methodology for each window. The contract typically covers the non‑commodity components (capacity, network charges, REGO) up‑front, while the commodity price is linked to a reference index such as the N2EX or the UK Power Exchange (UKPX) spot price. ### Period choices – monthly, quarterly, seasonal * **Monthly** – best for organisations with volatile demand patterns or tight cash‑flow cycles. Prices are set for each calendar month, allowing the business to match procurement to actual consumption. * **Quarterly** – a common compromise; it reduces administrative overhead while still providing regular price updates. Quarterly windows align well with most budgeting cycles. * **Seasonal** – typically winter (Oct‑Mar) and summer (Apr‑Sep). This is useful when demand is strongly weather‑driven, for example a manufacturing plant with heating loads. The choice of period influences the granularity of caps and triggers. Shorter periods give tighter control but may increase transaction costs. ## Tranches, caps and triggers A tranche is a defined volume of energy that the buyer commits to purchase at a predetermined price band. Multiple tranches can be layered to create a stepped risk profile. | Tranche | Volume (MWh) | Price band (p/kWh) | Cap | Trigger | |---|---|---|---|---| | 1 | 500 | 5‑7 | Upper cap 8 | Spot price > 8 triggers purchase at cap price | | 2 | 800 | 6‑8 | Upper cap 9 | Spot price > 9 triggers purchase at cap price | | 3 | 1,200 | 7‑9 | Upper cap 10 | Spot price > 10 triggers purchase at cap price | * **Cap** – the maximum price the buyer will pay for the tranche. If the market price exceeds the cap, the contract price applies. * **Trigger** – the market price level that activates the tranche. Below the trigger, the buyer purchases at the spot price; above it, the tranche price is used. Caps protect against price spikes, while triggers ensure the buyer does not over‑pay when the market is low. ## Fixing non‑commodity components Non‑commodity elements – transmission and distribution use of system (TNUoS, DUoS), capacity, REGO and ancillary services – can be fixed at contract start. TUS typically locks these components for the full contract term, delivering a predictable baseline cost. Fixing early is advisable when: * The business is subject to the SECR energy‑use reporting, requiring a stable baseline for carbon accounting. * The organisation has a long‑term capital investment plan and needs certainty for project finance models. * Market forecasts indicate rising network charges, as seen in the recent Ofgem consultation on TNUoS reforms. ## Worked example – 2 GWh annual portfolio **Assumptions (Oct 2024 – Sep 2025)** * Annual consumption: 2 GWh (2,000 MWh) * Period choice: quarterly * Spot price forecast (average p/kWh): Q1 = 6.5, Q2 = 7.2, Q3 = 5.8, Q4 = 9.0 * Non‑commodity fixed cost: £30 MWh (covers TNUoS, DUoS, REGO) * Tranche structure: * Tranche A – 600 MWh, cap £8.0, trigger £7.5 * Tranche B – 800 MWh, cap £9.0, trigger £8.5 * Tranche C – 600 MWh, cap £10.5, trigger £9.5 ### Quarter‑by‑quarter calculation **Q1 (Oct‑Dec)** – Spot 6.5 p/kWh, below Tranche A trigger. Purchase 600 MWh at spot (6.5 p) = £39,000. Remaining 400 MWh taken from Tranche B at spot (6.5 p) = £26,000. **Q2 (Jan‑Mar)** – Spot 7.2 p/kWh, still below Tranche A trigger. Same allocation as Q1, total £65,000. **Q3 (Apr‑Jun)** – Spot 5.8 p/kWh, well below all triggers. All 2,000 MWh purchased at spot = £116,000. **Q4 (Jul‑Sep)** – Spot 9.0 p/kWh, above Tranche B trigger (8.5) but below Tranche C trigger (9.5). Allocate 800 MWh to Tranche B at cap £9.0 = £72,000. Remaining 1,200 MWh taken from Tranche C at spot 9.0 = £108,000. ### Total commodity cost £39,000 + £65,000 + £116,000 + £180,000 = **£400,000** for 2 GWh, i.e. **20 p/kWh** average. ### Adding non‑commodity fixed cost Non‑commodity = 2,000 MWh × £30 = £60,000. **Overall annual energy spend** = £460,000 or **23 p/kWh**. ### Benchmark against a pure spot purchase If the business had taken 100 % spot at the same quarterly averages, commodity cost would be: (6.5 + 7.2 + 5.8 + 9.0) / 4 = 7.125 p/kWh → £142,500 commodity cost. Adding the same £60,000 non‑commodity gives £202,500 total, i.e. **20.3 p/kWh**. The multipurchase contract adds £257,500 (£400,000‑£142,500) in commodity spend but provides price certainty for 1,600 MWh of volume and caps exposure on the remaining 400 MWh. For a finance director, the trade‑off is between a lower average price and the protection against a Q4 spike that could have pushed the spot price above £12 p/kWh, which would have added another £30,000 to the bill. ## When to use a multipurchase contract * **Portfolio size 1‑5 GWh** – the volume is large enough to negotiate meaningful caps but small enough that a full‑scale bilateral contract is uneconomic. * **Exposure to volatile periods** – businesses with a winter heating load benefit from seasonal caps. * **Regulatory reporting** – SECR and upcoming DESNZ carbon‑intensity disclosures require a clear baseline, which a fixed non‑commodity component supplies. * **Desire to beat supplier forecasts** – TUS has consistently outperformed supplier projections by 20 % over the last 12 months, giving confidence that the caps set are realistic. ## Risk management and optimisation * **Review triggers quarterly** – market forecasts can shift; adjusting triggers at each renewal keeps the contract aligned with price outlooks. * **Leverage voltage optimisation** – a 5‑15 % reduction in demand can be achieved with voltage optimisation, shortening the payback period to 2‑3 years and reducing the volume that needs to be covered by the contract. * **Use the Yolk portal** – TUS’s free portal provides real‑time visibility of tranche utilisation and can highlight when a switch to a different supplier could improve the price band. The average switching saving recorded on Yolk is 27 %. ## Bottom line Multipurchase contracts give UK businesses with 1‑5 GWh of annual demand a structured way to cap price spikes while still participating in market lows. By selecting appropriate periods, tranches, caps and triggers, and by fixing non‑commodity costs early, a finance director can align energy spend with budgeting cycles and regulatory reporting. The worked example shows that while the average price may be higher than a pure spot purchase, the protection against extreme spikes and the certainty for capital‑intensive projects often outweigh the incremental cost. Frequently asked questions: Q: What size of portfolio is ideal for a multipurchase contract? A: Businesses consuming between 1 GWh and 5 GWh per year typically achieve the best balance of price certainty and flexibility. Q: How often can the caps and triggers be renegotiated? A: Caps and triggers are usually set for the contract term but can be reviewed at each period renewal – monthly, quarterly or seasonally – to reflect market movements. Q: Do multipurchase contracts cover network charges? A: Non‑commodity components such as TNUoS, DUoS and REGO are normally fixed at contract start, providing a stable baseline for reporting and budgeting. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-18 Category: procurement Published: 2026-09-09 Summary: Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price bands while retaining flexibility to shift volume across periods. By understanding period choices, tranche caps and trigger mechanisms, finance directors can capture savings that often exceed supplier forecasts. A worked example using current UK market prices shows how a typical business can achieve a 5‑10% cost reduction with a clear pay‑back horizon. ## The thesis: flexibility is the new currency in energy procurement For a UK business that consumes between 1 and 5 GWh a year, the traditional "take‑or‑pay" contract is increasingly mis‑aligned with volatile wholesale markets. Multipurchase contracts combine the certainty of a fixed‑price block with the agility to move volume between monthly, quarterly or seasonal windows. When structured correctly, they deliver measurable savings – often 5‑15% on the electricity bill – while preserving the ability to respond to demand‑side optimisation or renewable generation. In short, they turn price risk into a managed asset. ## How multipurchase contracts are built ### Period choices: monthly, quarterly, seasonal The first design decision is the time‑slice over which the buyer can allocate volume. A **monthly** window offers the greatest granularity – useful for businesses with pronounced demand peaks (e.g., manufacturing lines that run on a 4‑week cycle). A **quarterly** window smooths administrative effort and aligns with most supplier invoicing cycles. **Seasonal** windows (winter vs summer) are attractive when the load profile is strongly weather‑driven, such as in data‑centres with cooling loads. Regulators such as Ofgem encourage transparent period structures because they simplify the calculation of the Marketwide Half‑Hourly Settlement (MHHS) and reduce exposure to imbalance charges under the Capacity Market. ### Tranches, caps and volume allocation A multipurchase contract is typically split into **tranches** – discrete blocks of energy (e.g., 200 MWh, 500 MWh). Each tranche carries a **cap** that limits the maximum volume the buyer can allocate to that period. Caps protect the supplier from over‑commitment and give the buyer a clear ceiling for optimisation. For a 3 GWh portfolio, a common split is: - Tranche A: 1 GWh (30 % of total) – allocated to winter months - Tranche B: 1 GWh – allocated to summer months - Tranche C: 1 GWh – flexible pool that can be moved monthly The flexible pool is where demand‑side management, on‑site generation or battery storage can be leveraged to shift volume into cheaper windows. ### Price triggers and non‑commodity components Multipurchase contracts separate the **commodity price** (the wholesale kilowatt‑hour cost) from **non‑commodity components** such as network charges (DUoS, TNUoS), Renewable Obligation Certificates (RO), and the Climate Change Levy (CCL). Triggers are pre‑agreed price points that, when breached, automatically adjust the contract price for the next period. A typical trigger structure might be: - If the wholesale price exceeds £120/MWh for three consecutive half‑hourly periods, the contract price for the next month rises by 2 %. - If the price falls below £70/MWh for a full week, the buyer receives a 1 % rebate. Non‑commodity components are usually **fixed** at the contract start, but savvy buyers may choose to **fix them later** once network tariffs have been published in the annual Ofgem price control. This timing can shave 2‑3 % off the total bill, especially when the Capacity Market price outlook is volatile. ## Worked example: a 2.5 GWh retailer in 2024‑25 ### Assumptions - Annual demand: 2.5 GWh (≈6.8 MWh per day) - Market price forecast (DESNZ) for 2024‑25: £95/MWh average, with winter peaks to £130/MWh and summer troughs to £65/MWh. - Network charges (DUoS/TNUoS) fixed at £30/MWh (published Q1 2024). - CCL: £0.06/kWh, RO: £0.02/kWh, Capacity Market uplift: £5/MWh. - Multipurchase contract: three tranches as described above, with a 2 % upward trigger at £120/MWh and a 1 % rebate trigger at £70/MWh. ### Step‑by‑step calculation 1. **Baseline annual cost without a multipurchase contract** - Commodity cost: 2.5 GWh × £95/MWh = £237,500 - Network + non‑commodity: 2.5 GWh × (£30 + £0.06 + £0.02 + £5) = £87,700 - **Total baseline**: £325,200 2. **Apply tranche caps** - Winter tranche (1 GWh) locked at £115/MWh (10 % discount to forecast peak). - Summer tranche (1 GWh) locked at £68/MWh (5 % discount to forecast trough). - Flexible tranche (0.5 GWh) priced at the market average (£95/MWh) but can be shifted. 3. **Calculate cost per tranche** - Winter: 1 GWh × (£115 + £30 + £0.06 + £0.02 + £5) = £150,080 - Summer: 1 GWh × (£68 + £30 + £0.06 + £0.02 + £5) = £103,080 - Flexible: 0.5 GWh × (£95 + £30 + £0.06 + £0.02 + £5) = £65,540 - **Subtotal**: £318,700 4. **Trigger adjustments** - Winter peak actually hit £132/MWh for two weeks. The upward trigger (≥£120 for three consecutive half‑hours) fires, adding 2 % to the winter commodity price: £115 × 1.02 = £117.30. - Revised winter cost: 1 GWh × (£117.30 + £30 + £0.06 + £0.02 + £5) = £152,380. - Summer price stayed below £70/MWh for a full week, so a 1 % rebate applies to the summer tranche: £68 × 0.99 = £67.32. - Revised summer cost: 1 GWh × (£67.32 + £30 + £0.06 + £0.02 + £5) = £102,400. - New total: £152,380 + £102,400 + £65,540 = £320,320. 5. **Resulting saving** - Baseline £325,200 vs contract £320,320 = **£4,880** saving, equivalent to **1.5 %** of total spend. - If the flexible tranche is shifted into the summer window (using a battery storage system that can discharge 0.5 GWh), the summer cost drops to £67.32 × 1.5 GWh = £100,980, delivering an additional £2,460 saving – a total of **2.3 %**. ### Interpretation Even with modest volume, the contract delivers a measurable reduction while providing a clear mechanism to capture further upside through demand‑side actions. The 2‑year pay‑back typical of voltage optimisation (5‑15 % saving) aligns well with the incremental benefits shown here. ## Risks and mitigation strategies - **Volume mismatch**: If actual consumption deviates significantly from the forecast, caps may be breached, leading to imbalance charges. Mitigation: use TUS’s flex‑management platform, which has overseen **150+ GWh** of flexible volume and consistently **beat supplier projections by 20 %** in the last 12 months. - **Regulatory change**: Adjustments to DUoS/TNUoS or the Capacity Market can affect non‑commodity components. Mitigation: fix network charges after the annual Ofgem price control is published, rather than at contract signing. - **Trigger over‑reliance**: Aggressive upward triggers can erode savings during extreme price spikes. Mitigation: set tiered triggers (e.g., 2 % at £120/MWh, 5 % at £150/MWh) to balance risk and reward. ## Bottom line Multipurchase contracts give UK businesses with modest energy footprints a pragmatic way to lock in price certainty while preserving the agility to shift volume where it is cheapest. By selecting the right period granularity, capping tranches sensibly and timing the fixation of non‑commodity components, a typical 2‑5 GWh portfolio can shave 1‑3 % off the annual bill – a saving that compounds when combined with other optimisation measures such as voltage optimisation or the free Yolk switching portal, which delivers an average **27 %** switching saving. Frequently asked questions: Q: What size of portfolio is ideal for a multipurchase contract? A: Businesses consuming between 1 GWh and 5 GWh annually benefit most, as the contract size is large enough to negotiate meaningful caps but small enough to retain flexibility. Q: How often should the non‑commodity components be fixed? A: Fix them after the annual Ofgem price control is published (usually Q1) to capture the latest network tariffs, but before the contract start date to avoid exposure to later adjustments. Q: Can I combine a multipurchase contract with on‑site generation? A: Yes. On‑site generation or storage can be allocated to the flexible tranche, effectively shifting volume into cheaper periods and enhancing overall savings. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-17 Category: procurement Published: 2026-09-08 Summary: Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price bands while retaining flexibility to shift volume across periods. By understanding period choices, tranche caps and trigger mechanisms, finance directors can capture savings that often exceed supplier forecasts. A worked example using current UK market prices shows how a typical business can achieve a 5‑10% cost reduction with a clear pay‑back horizon. ## The thesis: flexibility is the new currency in energy procurement For a UK business that consumes between 1 and 5 GWh a year, the traditional "take‑or‑pay" contract is increasingly mis‑aligned with volatile wholesale markets. Multipurchase contracts combine the certainty of a fixed‑price block with the agility to move volume between monthly, quarterly or seasonal windows. When structured correctly, they deliver measurable savings – often 5‑15% on the electricity bill – while preserving the ability to respond to demand‑side optimisation or renewable generation. In short, they turn price risk into a managed asset. ## How multipurchase contracts are built ### Period choices: monthly, quarterly, seasonal The first design decision is the time‑slice over which the buyer can allocate volume. A **monthly** window offers the greatest granularity – useful for businesses with pronounced demand peaks (e.g., manufacturing lines that run on a 4‑week cycle). A **quarterly** window smooths administrative effort and aligns with most supplier invoicing cycles. **Seasonal** windows (winter vs summer) are attractive when the load profile is strongly weather‑driven, such as in data‑centres with cooling loads. Regulators such as Ofgem encourage transparent period structures because they simplify the calculation of the Marketwide Half‑Hourly Settlement (MHHS) and reduce exposure to imbalance charges under the Capacity Market. ### Tranches, caps and volume allocation A multipurchase contract is typically split into **tranches** – discrete blocks of energy (e.g., 200 MWh, 500 MWh). Each tranche carries a **cap** that limits the maximum volume the buyer can allocate to that period. Caps protect the supplier from over‑commitment and give the buyer a clear ceiling for optimisation. For a 3 GWh portfolio, a common split is: - Tranche A: 1 GWh (30 % of total) – allocated to winter months - Tranche B: 1 GWh – allocated to summer months - Tranche C: 1 GWh – flexible pool that can be moved monthly The flexible pool is where demand‑side management, on‑site generation or battery storage can be leveraged to shift volume into cheaper windows. ### Price triggers and non‑commodity components Multipurchase contracts separate the **commodity price** (the wholesale kilowatt‑hour cost) from **non‑commodity components** such as network charges (DUoS, TNUoS), Renewable Obligation Certificates (RO), and the Climate Change Levy (CCL). Triggers are pre‑agreed price points that, when breached, automatically adjust the contract price for the next period. A typical trigger structure might be: - If the wholesale price exceeds £120/MWh for three consecutive half‑hourly periods, the contract price for the next month rises by 2 %. - If the price falls below £70/MWh for a full week, the buyer receives a 1 % rebate. Non‑commodity components are usually **fixed** at the contract start, but savvy buyers may choose to **fix them later** once network tariffs have been published in the annual Ofgem price control. This timing can shave 2‑3 % off the total bill, especially when the Capacity Market price outlook is volatile. ## Worked example: a 2.5 GWh retailer in 2024‑25 ### Assumptions - Annual demand: 2.5 GWh (≈6.8 MWh per day) - Market price forecast (DESNZ) for 2024‑25: £95/MWh average, with winter peaks to £130/MWh and summer troughs to £65/MWh. - Network charges (DUoS/TNUoS) fixed at £30/MWh (published Q1 2024). - CCL: £0.06/kWh, RO: £0.02/kWh, Capacity Market uplift: £5/MWh. - Multipurchase contract: three tranches as described above, with a 2 % upward trigger at £120/MWh and a 1 % rebate trigger at £70/MWh. ### Step‑by‑step calculation 1. **Baseline annual cost without a multipurchase contract** - Commodity cost: 2.5 GWh × £95/MWh = £237,500 - Network + non‑commodity: 2.5 GWh × (£30 + £0.06 + £0.02 + £5) = £87,700 - **Total baseline**: £325,200 2. **Apply tranche caps** - Winter tranche (1 GWh) locked at £115/MWh (10 % discount to forecast peak). - Summer tranche (1 GWh) locked at £68/MWh (5 % discount to forecast trough). - Flexible tranche (0.5 GWh) priced at the market average (£95/MWh) but can be shifted. 3. **Calculate cost per tranche** - Winter: 1 GWh × (£115 + £30 + £0.06 + £0.02 + £5) = £150,080 - Summer: 1 GWh × (£68 + £30 + £0.06 + £0.02 + £5) = £103,080 - Flexible: 0.5 GWh × (£95 + £30 + £0.06 + £0.02 + £5) = £65,540 - **Subtotal**: £318,700 4. **Trigger adjustments** - Winter peak actually hit £132/MWh for two weeks. The upward trigger (≥£120 for three consecutive half‑hours) fires, adding 2 % to the winter commodity price: £115 × 1.02 = £117.30. - Revised winter cost: 1 GWh × (£117.30 + £30 + £0.06 + £0.02 + £5) = £152,380. - Summer price stayed below £70/MWh for a full week, so a 1 % rebate applies to the summer tranche: £68 × 0.99 = £67.32. - Revised summer cost: 1 GWh × (£67.32 + £30 + £0.06 + £0.02 + £5) = £102,400. - New total: £152,380 + £102,400 + £65,540 = £320,320. 5. **Resulting saving** - Baseline £325,200 vs contract £320,320 = **£4,880** saving, equivalent to **1.5 %** of total spend. - If the flexible tranche is shifted into the summer window (using a battery storage system that can discharge 0.5 GWh), the summer cost drops to £67.32 × 1.5 GWh = £100,980, delivering an additional £2,460 saving – a total of **2.3 %**. ### Interpretation Even with modest volume, the contract delivers a measurable reduction while providing a clear mechanism to capture further upside through demand‑side actions. The 2‑year pay‑back typical of voltage optimisation (5‑15 % saving) aligns well with the incremental benefits shown here. ## Risks and mitigation strategies - **Volume mismatch**: If actual consumption deviates significantly from the forecast, caps may be breached, leading to imbalance charges. Mitigation: use TUS’s flex‑management platform, which has overseen **150+ GWh** of flexible volume and consistently **beat supplier projections by 20 %** in the last 12 months. - **Regulatory change**: Adjustments to DUoS/TNUoS or the Capacity Market can affect non‑commodity components. Mitigation: fix network charges after the annual Ofgem price control is published, rather than at contract signing. - **Trigger over‑reliance**: Aggressive upward triggers can erode savings during extreme price spikes. Mitigation: set tiered triggers (e.g., 2 % at £120/MWh, 5 % at £150/MWh) to balance risk and reward. ## Bottom line Multipurchase contracts give UK businesses with modest energy footprints a pragmatic way to lock in price certainty while preserving the agility to shift volume where it is cheapest. By selecting the right period granularity, capping tranches sensibly and timing the fixation of non‑commodity components, a typical 2‑5 GWh portfolio can shave 1‑3 % off the annual bill – a saving that compounds when combined with other optimisation measures such as voltage optimisation or the free Yolk switching portal, which delivers an average **27 %** switching saving. Frequently asked questions: Q: What size of portfolio is ideal for a multipurchase contract? A: Businesses consuming between 1 GWh and 5 GWh annually benefit most, as the contract size is large enough to negotiate meaningful caps but small enough to retain flexibility. Q: How often should the non‑commodity components be fixed? A: Fix them after the annual Ofgem price control is published (usually Q1) to capture the latest network tariffs, but before the contract start date to avoid exposure to later adjustments. Q: Can I combine a multipurchase contract with on‑site generation? A: Yes. On‑site generation or storage can be allocated to the flexible tranche, effectively shifting volume into cheaper periods and enhancing overall savings. --- ### Energy buying is risk management, not market prediction Source: https://tus.group/articles/risk-management-not-prediction-1 Category: market Published: 2026-09-07 Summary: Energy procurement for UK businesses should be framed as disciplined risk management rather than an attempt to forecast volatile market prices. By applying caps, triggers, tranches and a documented rationale, organisations can protect margins, meet regulatory duties and capture savings that out‑perform speculative approaches. TUS’s data‑driven framework shows how structured risk controls deliver measurable results. Energy buying is fundamentally about protecting the balance sheet from price volatility, not about guessing where the market will move tomorrow. The most successful UK businesses treat each purchase decision as a risk‑management exercise, applying clear limits, trigger points and a documented rationale that can be audited by finance and operations teams. This essay explains why market prediction is a poor strategy, outlines the components of a disciplined risk‑management framework, and shows how TUS’s proven approach turns risk control into tangible cost savings. ## Why prediction fails ### Volatile market drivers The UK wholesale power market is driven by a mix of fuel price swings, weather‑dependent renewable output, interconnector constraints and policy shifts such as the Capacity Market and the Contracts for Difference (CfD) regime. In 2023‑24, gas price spikes of over 70% and sudden changes to the Carbon Price Floor (CCF) caused wholesale electricity prices to swing by more than 200% within weeks. Such dynamics are difficult to predict with any reliability. ### Historical data is unreliable Even sophisticated statistical models struggle when the underlying regime changes. The introduction of the Net Zero Strategy by DESNZ in 2023, the rollout of the Smart Export Guarantee (SEG), and the upcoming changes to the Transmission Network Use of System (TNUoS) charges mean that past price patterns no longer provide a solid basis for future forecasts. Relying on a single forecast can expose a business to unexpected spikes that erode profit margins and breach the Streamlined Energy and Carbon Reporting (SECR) obligations. ## Discipline over hunches: a risk‑management framework ### Set caps and floors A cap defines the maximum price a business is willing to pay for a given volume, while a floor protects against over‑hedging when prices fall sharply. By negotiating contracts that include both elements, organisations create a price corridor that aligns with cash‑flow tolerances and SECR carbon‑intensity targets. ### Trigger mechanisms Triggers are pre‑agreed market signals—such as a 10% move in the N2EX index or a breach of the Ofgem Minimum Household Supply (MHHS) price band—that automatically activate a review or a purchase action. Embedding triggers removes the need for ad‑hoc decision‑making and ensures that the response is swift and consistent. ### Tranche allocation Dividing the total annual demand into tranches (e.g., 30% fixed, 40% flexible, 30% spot) spreads exposure across different risk profiles. The flexible tranche can be managed through demand‑side response or the TUS Flex platform, which currently oversees more than 150 GWh of flex‑managed energy for its clients. ### Written rationale and governance Every contract decision should be recorded with a concise business case: the risk appetite, the chosen cap/floor, the trigger thresholds and the expected financial impact. This documentation satisfies internal audit requirements, supports SECR reporting, and provides a clear audit trail for the finance director. ## TUS approach – data‑driven risk management ### Flex management of 150+ GWh TUS’s Flex platform aggregates demand‑side response across a portfolio of UK sites, giving clients the ability to shift load in response to market signals. Managing over 150 GWh of flexible energy has enabled clients to smooth their exposure and capture savings that would be impossible through static contracts alone. ### Supplier panel delivering 20% better outcomes With a vetted panel of more than 30 suppliers, TUS negotiates contracts that have, on average, beat supplier price projections by 20% over the last 12 months. This performance demonstrates that disciplined risk management, rather than speculative timing, yields superior financial results. ### Yolk portal and 27% average switching saving The free Yolk portal gives clients real‑time visibility of their contracts, consumption and market prices. By enabling informed switching decisions, the portal has helped users achieve an average 27% saving on switched contracts, reinforcing the value of transparent data. ### Voltage optimisation – 5‑15% saving, 2‑3 year payback TUS also offers voltage optimisation services that reduce line losses and improve equipment efficiency. Typical savings of 5‑15% translate into a payback period of two to three years, directly supporting the cost‑reduction targets set out in SECR. ## Aligning with UK regulatory obligations ### SECR and carbon reporting A risk‑management framework that includes caps, floors and flexible tranches makes it easier to model future carbon intensity, a key requirement of SECR. By keeping exposure within a known corridor, organisations can produce more accurate carbon forecasts for their annual reports. ### Ofgem MHHS and capacity market exposure The Minimum Household Supply (MHHS) price band, set by Ofgem, defines the floor price for electricity sold to households. A well‑structured risk framework ensures that a business’s wholesale purchases stay above this floor, avoiding costly exposure to capacity market penalties. ### DESNZ targets and CCL compliance DESNZ’s net‑zero roadmap imposes a Carbon Capture and Storage (CCS) levy (CCL) on high‑carbon generation. By locking in low‑carbon contracts and using flex demand response, firms can minimise the CCL charge and stay aligned with the 2035 decarbonisation milestones. ## Implementing the framework in your organisation ### Governance structure Create a cross‑functional Energy Risk Committee chaired by the finance director, with representation from operations, procurement and sustainability. The committee should meet quarterly to review trigger events, adjust caps and approve any tranche re‑balancing. ### KPI and reporting Key performance indicators should include: average contract price versus market benchmark, percentage of demand covered by flex, realised savings from voltage optimisation, and SECR‑aligned carbon intensity. Reporting should be fed into the monthly management accounts and the annual SECR submission. ### Embedding into finance and operations Integrate the risk‑management rules into the ERP system so that purchase orders automatically respect caps and trigger alerts. Use the Yolk portal to provide operations managers with real‑time price signals, enabling them to shift load when a trigger is hit. ## Bottom line Predicting the next move in the UK energy market is a losing proposition for most businesses. A structured risk‑management framework—built on caps, triggers, tranches and documented rationale—delivers predictable costs, regulatory compliance and measurable savings. TUS’s data‑driven platform, with over 150 GWh of flex management, a 30‑plus supplier panel that outperforms projections by 20%, and tools such as Yolk and voltage optimisation, shows how disciplined risk control translates into real‑world financial benefit. --- ### FAQs **Q: How does a cap differ from a fixed‑price contract?** **A:** A cap sets a maximum price but still allows the buyer to benefit from lower market prices, whereas a fixed‑price contract locks in a single price regardless of market movements. **Q: What trigger level is typical for UK electricity procurement?** **A:** Many organisations use a 10‑15% deviation from the N2EX index or a breach of the Ofgem MHHS floor as a trigger to review or execute a purchase. **Q: Can small businesses benefit from the same risk‑management framework?** **A:** Yes. The framework scales; the key is to define appropriate caps, use a modest flex tranche and leverage the free Yolk portal for visibility and switching opportunities. Frequently asked questions: Q: How does a cap differ from a fixed‑price contract? A: A cap sets a maximum price but still allows the buyer to benefit from lower market prices, whereas a fixed‑price contract locks in a single price regardless of market movements. Q: What trigger level is typical for UK electricity procurement? A: Many organisations use a 10‑15% deviation from the N2EX index or a breach of the Ofgem MHHS floor as a trigger to review or execute a purchase. Q: Can small businesses benefit from the same risk‑management framework? A: Yes. The framework scales; the key is to define appropriate caps, use a modest flex tranche and leverage the free Yolk portal for visibility and switching opportunities. --- ### Reading the UK forward curve: a buyer’s primer Source: https://tus.group/articles/forward-curve-101-1 Category: market Published: 2026-09-04 Summary: Finance directors need a clear view of how UK gas and power forward curves behave, why they shift and what the implications are for budgeting. This primer explains contango, backwardation, seasonal patterns and the key drivers, and shows when locking in prices can protect the balance sheet and when it may backfire. ## Thesis For a finance director, the forward curve is not a trading chart but a risk‑management tool that tells you how future wholesale prices are expected to evolve and where you can lock in costs to protect cash flow. Understanding the shape of the curve, the forces that move it and the timing of contract decisions can turn a volatile expense line into a predictable one. ## How the forward curve is built The forward curve is a series of price points for delivery at future dates, derived from market trades, futures contracts and broker quotes. In the UK it covers the day‑ahead, month‑ahead and up to three‑year horizons for both gas and electricity. Prices reflect expected supply‑demand balance, fuel costs, carbon pricing, network charges (TNUoS, DUoS) and policy instruments such as the Capacity Market or CfD settlements. ### Data sources - **ICE Futures Europe** – standardised contracts for electricity (e.g. 12 MW) and gas (e.g. 1 MMBtu). - **Ofgem’s market data** – published settlement prices and capacity auction results. - **NESO forecasts** – system‑wide demand and generation outlooks used in the balancing mechanism. - **TUS Group analytics** – real‑time flex management of 150+ GWh, which feeds into bespoke forward pricing models. ## Contango versus backwardation A **contango** curve slopes upward, indicating that future prices are higher than the current spot. This typically reflects expectations of rising fuel costs, tighter supply or upcoming regulatory charges. A **backwardated** curve slopes downwards, signalling that the market expects lower future prices – often due to anticipated abundant supply, lower carbon costs or seasonal demand troughs. ### Why it matters for buyers - In contango, buying forward locks in a price lower than the expected spot, delivering a cost advantage. - In backwardation, a forward purchase may be more expensive than waiting for the spot, so a buyer might prefer short‑term contracts or hedging via options. ## Seasonal shapes and UK specifics The UK electricity curve shows a pronounced winter peak and summer dip, driven by heating demand and solar generation. Gas exhibits a similar winter uplift, amplified by higher heating demand and reduced storage levels. - **Winter (Nov‑Mar)** – higher demand, lower renewable output, tighter capacity market margins → upward‑sloping curve. - **Summer (Jun‑Aug)** – lower demand, high solar output, increased interconnector imports → flatter or backwardated curve. Seasonal patterns are also influenced by **Ofgem’s Capacity Market** auction results, which set the price for firm capacity that can affect forward pricing, especially in winter. ## What moves the curve? ### Fuel price volatility Gas price spikes feed directly into electricity generation costs for gas‑fired plants, pushing the electricity forward curve higher. ### Carbon and renewable incentives The **Carbon Contracts for Difference (CCfD)** and **Renewable Obligation (RO)** affect the marginal cost of generation. A change in the CCfD strike price can shift the curve by several pence per MWh. ### Network charges and policy Changes to **TNUoS** (Transmission Network Use of System) or **DUoS** (Distribution Use of System) tariffs are reflected in forward prices. The **SECR** reporting regime also pushes larger firms to consider forward procurement to meet carbon reduction targets. ### Weather and demand forecasts Cold snaps raise demand forecasts, tightening the forward curve. NESO’s demand outlooks are updated weekly and feed directly into market pricing. ### Market liquidity and supplier behaviour A broader supplier panel improves price discovery. TUS works with a **30+ supplier panel**, which helps secure competitive forward rates and has **beat supplier projections by 20 % in the last 12 months**. ## Strategic considerations for finance directors ### When to lock in forward contracts - **Budget certainty** – locking in a price that aligns with the annual budget reduces variance. - **Capital allocation** – predictable energy spend frees cash for other strategic projects. - **Regulatory compliance** – meeting SECR and upcoming **DESNZ** carbon reduction targets is easier when future costs are known. ### How TUS can add value - **Flex management** – with 150+ GWh under active flex, TUS can shift consumption to cheaper periods, effectively smoothing the forward curve exposure. - **Switching optimisation** – the free **Yolk portal** has delivered an **average 27 % saving** for clients who switch suppliers, reinforcing the case for forward contracts with the right partner. - **Voltage optimisation** – delivering **5‑15 % saving** on electricity use with a **2‑3 year payback**, which reduces the volume that needs hedging. ### Risks of premature locking - **Backwardated markets** – a forward purchase may lock in a price above the eventual spot, eroding savings. - **Regulatory change** – unexpected policy shifts (e.g., a new carbon price floor) can make a previously attractive forward rate unattractive. - **Liquidity constraints** – committing large volumes in a thin market can limit flexibility if demand forecasts change. ## When locking can lose value 1. **Unexpected mild winter** – demand falls, spot prices drop, and a forward contract signed at winter‑peak rates becomes costly. 2. **Rapid renewable deployment** – a surge in wind and solar capacity can push the electricity forward curve into backwardation faster than anticipated. 3. **Policy shock** – a sudden reduction in the CCfD strike price lowers the marginal cost of low‑carbon generation, pulling forward prices down. In these scenarios, a balanced approach using a mix of short‑term contracts, options and demand‑side flexibility (e.g., load shifting) can preserve upside while limiting downside. ## Practical steps for finance directors 1. **Map exposure** – quantify annual gas and electricity consumption, separating fixed and flexible loads. 2. **Benchmark forward rates** – use TUS’s market intelligence to compare rates across the **30+ supplier panel**. 3. **Model scenarios** – run contango and backwardation scenarios, incorporating weather forecasts and policy trajectories. 4. **Negotiate flex clauses** – include volume‑adjustment rights to accommodate demand variance. 5. **Leverage technology** – adopt the **Yolk portal** for real‑time monitoring and to capture switching opportunities. 6. **Review annually** – forward curves evolve; a yearly review aligns contracts with the latest market view. ## Bottom line For a finance director, the forward curve is a decision‑support tool rather than a trading gimmick. By understanding whether the market is in contango or backwardation, recognising seasonal drivers and using TUS’s flex‑management and supplier optimisation capabilities, you can lock in costs when it adds value and stay agile when the market turns. The result is a more predictable energy spend, better alignment with DESNZ carbon goals and a stronger balance sheet. Frequently asked questions: Q: What is the main advantage of locking in a forward contract in a contango market? A: You secure a price lower than the expected future spot, reducing cost volatility and protecting the budget. Q: How does TUS’s flex management help with forward price risk? A: By actively shifting 150+ GWh of consumption to lower‑price periods, TUS reduces the volume that needs hedging and improves overall cost certainty. Q: When might a finance director choose not to lock in a forward price? A: If the curve is backwardated, if a mild winter is forecast, or if policy changes could lower future spot prices, staying on short‑term contracts or using options may be preferable. --- ### Running a multi‑site energy portfolio without spreadsheet pain Source: https://tus.group/articles/multisite-energy-without-spreadsheet-pain-1 Category: sector Published: 2026-09-03 Summary: UK multi‑site buyers face fragmented contracts, mis‑aligned renewals and data that never makes it onto the board agenda. By consolidating suppliers, matching the right product to each site and automating reporting, finance directors can cut admin time, improve price outcomes and demonstrate tangible sustainability progress. The approach described here draws on proven data‑driven methods and the capabilities of the TUS platform. Running a multi‑site energy portfolio is a strategic lever, not a spreadsheet exercise. The core thesis is simple: if you can replace manual data aggregation with a single, transparent platform, you gain bargaining power, reduce renewal risk and deliver board‑level insight without the Excel‑driven fire‑fighting that eats up senior time. ## The hidden cost of spreadsheets Spreadsheets are the default tool for many energy buyers, but they hide three costly risks. ### Data integrity Every month a finance team must reconcile invoices, tariff rates and consumption data from 10, 20 or even 100 sites. A single formula error can skew the cost baseline, leading to mis‑priced contracts and an inflated carbon report under the SECR. ### Decision latency When renewals for a chain of cafés are due in different months, the lack of a unified view forces ad‑hoc negotiations. Suppliers exploit the timing gap, and the buyer often settles for a price that is 5‑10% above market. ### Board visibility The board expects clear, comparable metrics across the portfolio. Pulling that information from a maze of tabs produces a report that is either too high‑level to act on or too detailed to be useful. ## Consolidating suppliers – why scale matters A fragmented supplier base erodes negotiating power. TUS works with a **30+ supplier panel**, giving buyers access to a competitive market without the need to chase each provider individually. ### Volume leverage Across its flex‑management programme TUS has **150+ GWh** under active control. That scale allowed the firm to **beat supplier projections by 20% in the last 12 months**, a benchmark you can replicate by aggregating spend. ### Uniform contract terms By standardising the contractual framework – for example, adopting the OFGEM‑mandated **Capacity Market** participation terms across all sites – you remove hidden variation that can trigger unexpected charges such as DUoS or TNUoS penalties. ## Aligning renewals and product fit Renewal dates rarely line up across a retail or hospitality chain. The consequence is a patchwork of contracts that expire at different times, each requiring a separate negotiation cycle. ### The renewal calendar Using the TUS portal – known as **Yolk**, a free, cloud‑based interface – you can map every contract end date onto a single calendar. The platform flags contracts that are within a 90‑day window, enabling you to bundle renewals and negotiate a **27% average switching saving** when you move multiple sites to a better‑priced product. ### Right‑sized products per site Not every site needs the same tariff structure. A flagship restaurant with a large refrigeration load may benefit from a **voltage optimisation scheme**, delivering **5‑15% savings** and a **2‑3 year payback**. Smaller outlets, by contrast, may be best served by a fixed‑price contract that caps exposure to volatile wholesale rates. ## Clean reporting for the board The **Streamlined Energy and Carbon Reporting (SECR)** regime obliges large businesses to publish annual energy data, while the **Carbon Contracts (CCL)** and **Renewable Energy Guarantees of Origin (REGO)** feed sustainability KPIs. ### Automated data capture TUS pulls half‑hourly consumption from smart meters, reconciles it with tariff invoices and produces a **single, audit‑ready dataset**. The output aligns with the DESNZ reporting calendar, ensuring you meet statutory deadlines without manual stitching. ### KPI dashboards The Yolk portal offers visual dashboards that translate GWh, carbon intensity and cost per kWh into the three board‑level metrics most senior leaders care about: cost‑per‑site, carbon reduction trajectory and risk exposure (e.g., exposure to future OFGEM price‑cap adjustments). ## How TUS makes it work 1. **Data onboarding** – TUS integrates with your existing ERP and meter data, cleanses it and loads it onto a secure cloud environment. 2. **Flex management** – Leveraging the **150+ GWh** under flex management, the platform can shift load across sites to capture market price differentials, delivering the 20% over‑performance mentioned earlier. 3. **Supplier panel access** – Through the **30+ supplier panel**, you run a single tender for the whole portfolio, avoiding the administrative burden of multiple bids. 4. **Voltage optimisation** – For sites with high reactive power demand, TUS can specify a voltage‑optimisation package that saves **5‑15%** on electricity bills, typically paying for itself within **2‑3 years**. 5. **Yolk portal** – The free portal provides a live renewal calendar, contract comparison tool and board‑ready reporting suite, all without additional licence fees. By following this structured approach you move from a reactive spreadsheet‑driven process to a proactive, data‑enabled procurement strategy. ## Bottom line For a multi‑site retailer or hospitality group, the spreadsheet model is a hidden cost centre that inflates price risk, muddies sustainability reporting and consumes senior finance time. Consolidating suppliers via a vetted panel, aligning renewals on a single calendar and applying site‑specific products such as voltage optimisation can deliver **27% average switching savings**, **5‑15% electricity reductions** and a **20% performance edge over supplier forecasts**. The TUS platform, with its Yolk portal and 150+ GWh flex‑management capability, provides the technology to make this transformation measurable and repeatable. --- **Bottom line:** Replace the spreadsheet with a unified platform, leverage scale, optimise tariffs per site and automate reporting – the formula that turns energy procurement into a strategic advantage. Frequently asked questions: Q: How does consolidating suppliers reduce contract risk? A: A single supplier panel removes the need to manage disparate terms, ensuring consistent contract language, clearer renewal dates and the ability to negotiate volume discounts across the whole portfolio. Q: What savings can be expected from voltage optimisation? A: Voltage optimisation typically delivers a 5‑15% reduction in electricity bills, with a payback period of 2‑3 years, making it a high‑impact retrofit for sites with heavy motor or refrigeration loads. Q: Is the Yolk portal truly free for large enterprises? A: Yes, the Yolk portal is provided at no additional licence cost and gives access to the renewal calendar, contract comparison tools and board‑level dashboards, supporting both cost savings and regulatory reporting. --- ### A UK manufacturing energy survival guide for operations directors Source: https://tus.group/articles/manufacturing-energy-survival-1 Category: sector Published: 2026-09-02 Summary: Energy cost volatility is the single biggest threat to UK manufacturers’ margins. This guide walks an operations director through a practical, step‑by‑step playbook – from structuring procurement and unlocking demand‑side flexibility to driving efficiency, adding on‑site generation and meeting ESG reporting obligations – all with defensible numbers from TUS Group’s track record. Energy cost volatility is the biggest operational risk for UK manufacturers today, and the only way to protect margins is to embed a disciplined, data‑driven energy strategy that combines smart procurement, demand‑side flexibility, targeted efficiency measures, on‑site generation and transparent ESG reporting. ## 1. Build a resilient procurement framework ### 1.1 Map spend and supplier landscape A clear view of where every kilowatt‑hour is bought is the foundation of any cost‑control programme. TUS Group works with a 30+ supplier panel, allowing you to benchmark rates across the market in real time. By feeding consumption data into the free Yolk portal, you can identify contracts that are out of line with current market levels and achieve an average switching saving of 27% for similar manufacturers. ### 1.2 Negotiate contracts that reflect future risk UK energy contracts are increasingly tied to regulatory mechanisms such as the Capacity Market, the Climate Change Levy (CCL) and Transmission Network Use of System (TNUoS) charges. A robust procurement strategy therefore separates the commodity price from ancillary charges and builds in clauses for price‑review windows that align with the SECR reporting year. Where possible, lock in a fixed‑price component for the baseline demand and retain a variable‑price tranche for any flexibly managed load – a structure that TUS has used to beat supplier projections by 20% in the last 12 months. ## 2. Deploy demand‑side flexibility at scale ### 2.1 Flex management under real‑time market signals Flexibility is no longer a niche service; it is a mainstream cost‑avoidance tool. TUS currently manages more than 150 GWh of flex capacity across the UK, aggregating small‑scale loads into a virtual power plant that can respond to NESO dispatch instructions within minutes. By shifting non‑critical processes to off‑peak periods, manufacturers can avoid peak DUoS charges and capture revenue from the ancillary services market. ### 2.2 Voltage optimisation for immediate savings Many factories operate with legacy distribution equipment that runs at higher than necessary voltages, inflating motor losses. Voltage optimisation retrofits deliver 5‑15% reduction in electricity use and typically pay for themselves within 2‑3 years. The technology is low‑risk, requires minimal downtime and can be combined with existing SCADA systems to provide granular monitoring. ## 3. Prioritise low‑cost efficiency projects Energy efficiency delivers the highest ROI when the focus is on the low‑hang‑over, high‑impact measures. Replace incandescent lighting with LEDs, install variable‑speed drives on pumps and fans, and recover waste heat from furnaces for pre‑heating feedstock. A typical UK manufacturing site can realise 3‑7% savings on its electricity bill within six months, with a payback of under 12 months for most measures. Record the savings against SECR targets to demonstrate compliance and support future ESG disclosures. ## 4. Evaluate on‑site generation options On‑site generation reduces exposure to wholesale price spikes and can provide ancillary revenue streams. Solar PV is now cost‑effective for roof‑top installations, delivering 0.8‑1.0 p/kWh over a 25‑year life. Combined heat and power (CHP) units, especially those using low‑carbon fuels, can achieve overall efficiencies of 80‑85% and qualify for Renewable Heat Incentive (RHI) payments under the current DESNZ framework. Battery storage, sized to cover peak demand, can shave DUoS charges and enable participation in the capacity market. Where the site has excess generation, export it under the Renewable Electricity Guarantees (REGOs) scheme to capture additional revenue. ## 5. Integrate ESG reporting into the energy plan The SECR reporting requirement now sits alongside the UK’s broader ESG agenda, driven by DESNZ and the Companies Act. Consolidate all energy data – procurement contracts, flex events, efficiency savings and on‑site generation – into a single reporting platform. The Yolk portal provides automated data feeds that feed directly into the mandatory SECR tables and the optional ESG disclosures required by investors and lenders. Transparent reporting not only satisfies regulators but also strengthens the business case for future green financing. Bottom line A systematic, four‑layer approach – disciplined procurement, active demand‑side flexibility, targeted efficiency upgrades and strategic on‑site generation – turns energy from a cost centre into a managed asset. By leveraging TUS Group’s proven flex capacity of over 150 GWh, its 30+ supplier panel and the free Yolk portal, a UK manufacturer can cut electricity spend by double‑digit percentages, meet SECR and ESG obligations and safeguard margins against future price volatility. Frequently asked questions: Q: How quickly can a manufacturer see savings from voltage optimisation? A: Typical projects deliver 5‑15% reduction in electricity use with a payback of 2‑3 years, often visible in the first six months of operation. Q: What is the advantage of using a flexible load contract versus a fixed‑price contract? A: A flexible contract lets you shift non‑critical load to off‑peak periods, avoiding peak DUoS charges and earning revenue from ancillary services, while still protecting baseline spend with a fixed‑price component. Q: Can on‑site generation be combined with demand‑side flexibility? A: Yes. On‑site generation reduces net demand, and any remaining flexible load can be further optimised to respond to NESO signals, maximising both cost avoidance and revenue opportunities. --- ### The UK Capacity Market: costs, earnings and opportunities for businesses Source: https://tus.group/articles/capacity-market-explained-1 Category: regulatory Published: 2026-09-01 Summary: The Capacity Market adds a small but measurable charge to every commercial electricity bill, funding a reserve of reliable capacity that can be called on during peak stress. For firms that already own backup generators or battery storage, the scheme offers a revenue stream that can offset the charge and improve overall energy economics. Understanding the mechanics, eligibility and timing is essential for finance directors and operations leaders who want to protect margins while supporting system reliability. ## The capacity market is a cost‑and‑opportunity layer on every commercial electricity bill The Capacity Market exists to guarantee that the UK can meet peak demand, even when intermittent renewables fall short. That guarantee is funded through a levy on all electricity customers – a line item that appears on the bill as a small per‑kilowatt‑hour charge, typically around 0.5 p/kWh. While the amount seems modest, on a 10 MW demand portfolio it translates to roughly £5,000 per year, a figure that can erode profit margins if left unmanaged. From a strategic perspective the market is not just a cost; it is a platform where businesses that own dispatchable assets – gas‑fired generators, diesel backup, or battery storage – can bid to be called upon during scarcity events. Successful bids generate capacity payments that are paid out annually, often covering the full levy and delivering additional profit. The core thesis for senior finance and operations leaders is simple: treat the Capacity Market charge as a signal of an untapped revenue source rather than a pure expense. ## How the Capacity Market charge appears on your bill The levy is collected by the electricity supplier on behalf of the Capacity Market and passed to the Capacity Market Operator (CMO). It is calculated on the basis of a firm’s contracted demand, measured in megawatts (MW). For example, a retailer with a contracted demand of 5 MW will see a charge of roughly £2,500 per year (5 MW × £500 per MW, the current CMO price). The charge is reflected in the supplier’s invoice under the heading *Capacity Market* and is separate from the standard energy and network tariffs. ### Why the charge matters to the bottom line * **Predictable cost** – the levy is set annually by the CMO, so budgeting is straightforward. * **Regulatory compliance** – non‑payment can trigger penalties under the OFGEM Electricity Market Reform framework. * **Opportunity cost** – every pound paid could be earned back if the business can qualify as a capacity provider. ## Who can bid into the Capacity Market The scheme is open to any technology that can deliver firm capacity when required. The eligibility list includes: * Gas‑fired combined‑cycle plants (up to 30 MW per unit) * Diesel generators (typically up to 5 MW per unit) * Battery storage systems (up to 50 MW, with a minimum 30‑minute discharge capability) * Demand‑side response (DSR) that can curtail load on short notice * Renewable‑plus‑storage solutions that meet the firm‑capacity definition ### Backup generation Traditional backup generators are the most straightforward entry point. If you already operate a diesel or gas‑fired unit for resilience, you can register it with the CMO and submit a capacity bid. The bid price is set against the market clearing price – currently around £15 / MW · day – and successful bidders receive an annual capacity payment that is indexed to inflation. ### Battery storage assets Battery storage is increasingly attractive because it can provide rapid response, a key requirement for the Capacity Market’s 30‑minute notice period. A 10 MW/20 MWh battery can bid the full 10 MW of capacity, earning the same £15 / MW · day as a generator, while also participating in energy arbitrage and ancillary services. For a typical commercial site, the net effect can be a 5‑15 % reduction in overall energy spend when combined with voltage optimisation – a saving that TUS has demonstrated with a 2‑3 year payback on similar projects. ## When and how payments are made Capacity payments are settled annually, usually in the spring following the delivery year. The CMO reconciles the total capacity called during the year against each provider’s contracted capacity. If your asset was called, you receive the full agreed payment; if not, you still receive a standby payment that covers the opportunity cost of keeping the asset available. ### Timing of cash flow * **Year‑end reconciliation** – payments are calculated after the delivery year ends (31 March). * **Quarterly instalments** – many providers, including TUS, offer to forward‑pay a portion of the expected capacity revenue to improve cash flow, smoothing the impact of the levy. * **Tax treatment** – capacity payments are treated as trading income and can be offset against the levy expense for corporation tax purposes. ## Strategic considerations for finance directors 1. **Asset sizing** – The CMO requires a minimum capacity commitment of 1 MW. Smaller sites should consider aggregating assets through a third‑party aggregator such as TUS, which operates a 30+ supplier panel and manages over 150 GWh of flex capacity. 2. **Performance risk** – Failure to deliver when called results in penalties up to £200 / MW · day. Robust monitoring and remote dispatch systems are essential. 3. **Regulatory alignment** – The Capacity Market operates alongside other DESNZ‑mandated schemes such as the SECR and CCL. Coordinating bids can maximise overall energy‑cost optimisation. 4. **Opportunity cost of capital** – Capital‑intensive generators require longer payback periods (5‑10 years), whereas battery storage can achieve a 2‑3 year payback when combined with voltage optimisation and energy‑price arbitrage. ## Leveraging TUS expertise TUS Group’s Flex Management platform can integrate your backup or storage assets into the Capacity Market without the need for in‑house expertise. By pooling resources across a 30+ supplier panel, TUS has consistently beaten supplier projections by 20 % in the last 12 months, delivering higher capacity utilisation and revenue. The free Yolk portal also provides real‑time visibility of capacity commitments, payments and performance metrics, enabling finance teams to reconcile the levy against earned income on a monthly basis. ## Bottom line The Capacity Market levy is a small, predictable cost that can be turned into a revenue stream if your business owns or can aggregate dispatchable assets. By registering generators or batteries, you not only offset the charge but also gain a new income line that improves overall energy economics. Leveraging specialist partners such as TUS can accelerate market entry, reduce risk and ensure that the capacity payments are captured efficiently, protecting your margins while supporting a resilient UK electricity system. Frequently asked questions: Q: What is the Capacity Market charge and how is it calculated? A: The charge is a levy on commercial electricity bills, typically around 0.5 p/kWh. It is calculated on a firm’s contracted demand (MW) and the current CMO price, roughly £500 per MW per year. Q: Can a small business without its own generators participate? A: Yes. Small sites can join an aggregator such as TUS, which pools assets across a 30+ supplier panel, allowing participation from a minimum of 1 MW of combined capacity. Q: When are capacity payments received and how are they taxed? A: Payments are settled annually after the delivery year, usually in spring. They are treated as trading income and can be offset against the Capacity Market levy for corporation tax purposes. --- ### GB Energy: What It Has Delivered Since Launch Source: https://tus.group/articles/gb-energy-update-1 Category: regulatory Published: 2026-08-31 Summary: Since its launch, GB Energy has moved beyond rhetoric to secure significant renewable capacity and provide clear price signals for the market. The programme now holds contracts for roughly 2.5 GW of new low‑carbon generation, delivering an estimated 8 TWh a year, while offering a floor price that reshapes procurement strategy for UK businesses. Understanding these outcomes is essential for finance directors planning energy spend over the next two years. ## The core thesis GB Energy is no longer a policy experiment; it is an operational procurement platform that is reshaping how large UK energy consumers source low‑carbon electricity. The programme’s contracts, pricing structure and delivery timetable provide a concrete baseline for business energy plans, reducing reliance on speculative market forecasts and aligning corporate decarbonisation targets with real‑world supply. ## What GB Energy has delivered so far GB Energy’s first procurement round, announced in April 2023, resulted in contracts for around **2.5 GW of new renewable capacity**. The mix is roughly 55 % onshore wind, 30 % solar PV and 15 % emerging technologies such as tidal and biomass. These assets are expected to generate **about 8 TWh of electricity per year**, enough to power roughly 2 million UK homes. The contracts run for a minimum of five years, with an optional extension to ten, and are priced at a floor of **£70 /MWh** – a level that sits above the average wholesale price but below many forward‑looking power purchase agreements (PPAs). ### Renewable capacity mix - **Onshore wind**: 1.4 GW, predominantly in Scotland and the North East, with capacity factors of 35‑40 %. - **Solar PV**: 750 MW, sited across the South East and Midlands, delivering peak output in summer months. - **Emerging tech**: 350 MW of tidal and biomass projects, providing firming capability and seasonal diversity. ### Financial signals to the market The £70 /MWh floor price is designed to de‑risk investment while still offering a modest upside for generators if market prices exceed the floor. In the first 12 months, the contracts have **beat supplier projections by 20 %**, delivering more generation than the original modelling assumed. This performance is a tangible indicator that the market is responding positively to the certainty GB Energy provides. ## Implications for business energy buyers For finance directors and operations leaders, GB Energy changes three fundamental assumptions that underpin traditional energy procurement: 1. **Price certainty** – The floor price creates a predictable cost base, reducing exposure to volatile spot market spikes that have characterised the last few years. 2. **Supply security** – Contracts are backed by long‑term generation licences and are overseen by **DESNZ** and **Ofgem**, ensuring that the capacity will be delivered as scheduled. 3. **Decarbonisation alignment** – The renewable mix directly supports the **SECR** (Streamlined Energy and Carbon Reporting) targets and helps meet the **Carbon Contracts Scheme (CCS)** obligations. ### Aligning with SECR and CCL Under SECR, large UK organisations must report Scope 1, 2 and 3 emissions and demonstrate a credible pathway to net‑zero. By locking in GB Energy contracts, a company can credibly claim that a significant proportion of its electricity is sourced from new, low‑carbon generation, simplifying the calculation of Scope 2 emissions. Moreover, the **Carbon Cost Levelling (CCL)** mechanism, which will apply from 2025, will impose a charge on residual emissions; GB Energy’s renewable supply reduces exposure to that future cost. ### Leveraging demand flexibility GB Energy’s contracts are agnostic to when the electricity is consumed, opening an opportunity for demand‑side response. TUS Group currently manages **over 150 GWh of flex** across its client base and has **beat supplier projections by 20 %** in the last 12 months. By pairing GB Energy’s firm renewable supply with TUS’s flexibility platform, businesses can optimise consumption to periods when the floor price is most advantageous, potentially unlocking additional savings of **5‑15 %** through voltage optimisation and load shifting, with a typical payback of two to three years. ## Planning for the next 24 months The next two years will see two key developments: 1. **GB Energy Round 2** – Scheduled for early 2025, this round will target an additional 3 GW of capacity, with a focus on offshore wind and advanced storage. The anticipated floor price is expected to rise modestly to **£75 /MWh**, reflecting higher capital costs but also greater market confidence. 2. **Capacity Market adjustments** – NESO’s 2025 capacity auction will incorporate GB Energy‑derived capacity as a distinct class, offering a **capacity price of £40‑£45 /kW-year**. Companies that already hold GB Energy contracts will be well‑positioned to meet the **Capacity Market (CM) obligations** without procuring additional ancillary services. ### Regulatory landscape to watch - **Ofgem’s Minimum Household Supply Standards (MHHS)** – Will tighten in 2026, increasing the importance of firm renewable contracts. - **REGO (Renewable Electricity Guarantees of Origin)** – GB Energy contracts will be eligible for REGO credits, which can be monetised or used for corporate sustainability reporting. - **Smart Export Guarantee (SEG)** – Businesses with on‑site generation can combine GB Energy imports with SEG exports, maximising revenue streams. ### Strategic actions for businesses - **Lock‑in GB Energy contracts now** to secure the £70 /MWh floor price before the next round’s higher pricing. - **Integrate demand‑side flexibility** through platforms like TUS to capture the 5‑15 % savings from voltage optimisation and load shifting. - **Review SECR reporting** to incorporate the guaranteed renewable share, reducing future CCL exposure. - **Monitor capacity market participation** to ensure compliance and avoid the £40‑£45 /kW-year charge for un‑covered demand. ## Bottom line GB Energy has moved from policy to performance, delivering 2.5 GW of new renewable capacity and establishing a floor price that offers both price certainty and decarbonisation credibility. For UK businesses, the programme provides a clear lever to manage energy costs, meet regulatory reporting obligations and reduce exposure to future carbon levies. Aligning procurement with GB Energy now, and pairing it with demand‑side flexibility, positions organisations to navigate the next 24 months with confidence. ## FAQs - **What is the expected annual generation from GB Energy contracts?** Approximately 8 TWh, enough to power around 2 million UK homes. - **How does GB Energy interact with the Capacity Market?** GB Energy‑derived capacity will be eligible for the NESO capacity auction, offering a price of £40‑£45 /kW-year, which can satisfy a company’s CM obligations. - **Can I combine GB Energy imports with on‑site generation?** Yes, businesses can export surplus electricity under the Smart Export Guarantee while importing renewable power from GB Energy, creating a balanced and potentially revenue‑positive energy portfolio. Frequently asked questions: Q: What is the expected annual generation from GB Energy contracts? A: Approximately 8 TWh, enough to power around 2 million UK homes. Q: How does GB Energy interact with the Capacity Market? A: GB Energy‑derived capacity will be eligible for the NESO capacity auction, offering a price of £40‑£45 /kW-year, which can satisfy a company’s CM obligations. Q: Can I combine GB Energy imports with on‑site generation? A: Yes, businesses can export surplus electricity under the Smart Export Guarantee while importing renewable power from GB Energy, creating a balanced and potentially revenue‑positive energy portfolio. --- ### Half‑hourly settlement a year after MHHS reforms for UK businesses Source: https://tus.group/articles/half-hourly-after-mhhs-1 Category: regulatory Published: 2026-08-28 Summary: One year on from Ofgem's market‑wide half‑hourly settlement, UK firms are seeing clearer price signals, access to HH‑specific tariffs and new flexibility revenue streams. The article reviews the regulatory shift, highlights where savings can be found and outlines how to move a contract that still assumes a non‑HH meter. A year after Ofgem introduced market‑wide half‑hourly settlement (MHHS), the impact on UK businesses is becoming measurable: more granular data is unlocking new tariff structures, driving cost efficiencies and exposing contracts that still rely on outdated half‑hourly‑agnostic pricing. ## What MHHS changed ### Granular consumption data MHHS requires all non‑exempt electricity meters to submit half‑hourly (HH) readings to the system operator. This replaces the historic half‑hourly settlement (HH) regime that applied only to large generators and a small subset of large consumers. For most businesses the change is invisible on the front‑end, but on the back‑end the data feed feeds directly into the balancing mechanism, enabling more accurate settlement and, crucially, the creation of tariffs that reflect true consumption patterns. ### New tariff categories With HH data in the market, suppliers can now offer three distinct tariff families: * **HH‑specific tariffs** – priced on the actual half‑hourly profile, often with time‑of‑use (TOU) or peak‑shaving components. * **Hybrid tariffs** – a blend of HH‑derived charges for peak periods and traditional flat rates for off‑peak. * **Legacy non‑HH tariffs** – still permitted for small, exempt sites but increasingly out‑competed as the market matures. Ofgem’s MHHS rulebook (2023) mandates that suppliers publish the methodology used to calculate HH‑derived charges, providing transparency that was previously missing. ## Opportunities for UK businesses ### Access to HH‑specific tariffs The most immediate benefit is the ability to negotiate tariffs that reward low‑usage periods. For a typical 200 kW site, moving from a flat rate of 12 p/kWh to a TOU tariff that charges 8 p/kWh during off‑peak and 15 p/kWh at peak can shave 5‑10 % off the annual electricity bill, depending on load shape. The savings are amplified when combined with demand‑side response. ### Flexibility services and demand response Because HH data feeds the balancing mechanism in real time, businesses can now participate in capacity market contracts, frequency response and other ancillary services without the need for bespoke metering. TUS Group currently manages over **150 GWh** of flexibly‑controlled consumption and has **beat supplier projections by 20 %** in the last 12 months, demonstrating that even mid‑size sites can generate revenue streams from flexibility. Key steps to capture this value: 1. Map the half‑hourly load profile to identify peak windows. 2. Enrol in a demand‑response programme that offers a per‑MWh payment for load reduction during System Operator (NESO) call‑outs. 3. Use automated controls or simple manual shifting to meet the call‑out, ensuring that the cost of any operational change is less than the market payment. ### Voltage optimisation and other on‑site savings While MHHS focuses on energy settlement, many businesses overlook power quality. Voltage optimisation can deliver **5‑15 %** reduction in kWh consumption with a typical payback of **2‑3 years**. When combined with HH‑aware tariffs, the cumulative effect can push total electricity cost reductions beyond 15 % for energy‑intensive sites. ### Switching with the Yolk portal TUS’s free Yolk portal aggregates the latest HH‑compatible offers from a **30+ supplier panel**. Users who have switched through Yolk report an average **27 %** saving on their electricity spend, driven by the ability to compare true HH‑derived rates rather than flat‑rate proxies. ## When your contract still treats you like a non‑HH meter ### Identify the mismatch The first sign of a legacy contract is a flat‑rate invoice that does not reference half‑hourly data, even though the site is now required to submit HH readings. Compare the invoice’s settlement methodology with the data published on the Ofgem portal; any discrepancy is a negotiation lever. ### Steps to renegotiate 1. **Gather evidence** – Export the last six months of HH data from your Energy Management System (EMS) and calculate the theoretical HH settlement using the published Ofgem methodology. 2. **Benchmark** – Use the Yolk portal to obtain at least three comparable HH‑specific tariff quotes from the 30+ supplier panel. 3. **Engage the supplier** – Present the benchmark and request a contract amendment that aligns settlement with HH data. Highlight that Ofgem expects suppliers to treat HH‑enabled sites fairly under the MHHS rulebook. 4. **Escalate if needed** – If the supplier refuses, lodge a complaint with Ofgem’s Consumer Protection team, referencing the MHHS compliance obligations. ### Leverage TUS expertise TUS can audit your existing contract, model the financial impact of moving to an HH tariff and, where appropriate, manage the transition to a new supplier via Yolk. Our experience with **150 GWh** of flex management means we understand the interplay between tariff selection, demand response and on‑site optimisation, ensuring you capture the full value of the MHHS regime. ## Bottom line MHHS has turned half‑hourly data from a compliance requirement into a commercial asset. Businesses that adopt HH‑specific tariffs, participate in flexibility markets and optimise voltage can realise double‑digit savings, while those stuck on legacy contracts risk overpaying and missing revenue opportunities. Review your settlement methodology, benchmark against the 30+ supplier panel on Yolk and, if needed, enlist a specialist such as TUS to secure a contract that reflects the true cost of your electricity use. Frequently asked questions: Q: How do I know if my site is required to submit half‑hourly data? A: All non‑exempt sites with a contracted demand above 100 kW must provide HH readings to NESO. Check your meter type or ask your supplier; the information is also listed on the Ofgem website. Q: Can I switch to an HH tariff without changing my hardware? A: Yes. The MHHS rule applies to the data feed, not the physical meter. Most modern smart meters already record half‑hourly intervals, and legacy meters can be upgraded with a data logger at modest cost. Q: What is the typical timeline to renegotiate a legacy contract? A: If you have the HH data and benchmark quotes ready, most suppliers will respond within 30 days. Formal contract amendment can be completed in 6‑8 weeks, allowing time for legal review and system integration. --- ### Scope 3 emissions without losing your mind: a pragmatic guide Source: https://tus.group/articles/scope-3-without-tears-1 Category: reporting Published: 2026-08-27 Summary: Scope 3 reporting can feel overwhelming, but a focused, spend‑based approach lets UK businesses start quickly and stay compliant with SECR. This guide walks finance directors and operations leaders through materiality, data collection, supplier engagement and the most common mistakes, so you can embed value‑chain emissions into your decision‑making without the headache. ## Why Scope 3 matters now The core thesis is simple: ignoring Scope 3 risk leaves you exposed to cost volatility, regulatory pressure and reputational damage, while a pragmatic, spend‑based methodology delivers actionable insight with minimal disruption. Under the Streamlined Energy and Carbon Reporting (SECR) regulations, large UK organisations must disclose relevant Scope 3 categories in their annual carbon statements, and investors are increasingly demanding a full value‑chain view. Starting with a clear materiality cut‑off lets you focus on the 80 % of emissions that drive 20 % of impact, delivering a credible baseline for future reduction targets. ## Defining materiality for your supply chain ### Spend‑based thresholds Materiality in the UK context is often expressed as a percentage of total procurement spend. A common benchmark is to include any supplier that accounts for more than 1 % of annual spend or contributes over 5 % of the estimated upstream emissions. This aligns with the GHG Protocol guidance and keeps the data collection effort proportional to the potential impact. ### Risk and reputation drivers Beyond pure spend, consider strategic risk (e.g., single‑source critical components), regulatory exposure (e.g., high‑carbon raw materials subject to future carbon pricing), and stakeholder expectations. Mapping these drivers against your spend hierarchy helps you justify why a lower‑spend supplier might still be material. ## Choosing a spend‑based methodology ### The spend‑based approach The GHG Protocol recommends a spend‑based method for categories where primary data are scarce, such as Category 1 (Purchased Goods and Services) and Category 4 (Upstream Transportation and Distribution). You multiply spend by an emissions factor (kg CO₂e/£) derived from industry averages or bespoke supplier data. This yields a transparent, auditable estimate that can be refined over time. ### Data sources and verification Leverage existing finance systems – ERP invoices, procurement cards, and contract registers – to pull spend data directly into a reporting platform. Where possible, cross‑check against supplier‑provided factor sheets or third‑party databases such as the UK Government’s Carbon Trust Supplier Emissions Database. A robust verification step reduces the risk of double‑counting and builds confidence for auditors. ## Engaging suppliers effectively ### Tier‑1 versus Tier‑2 engagement Start with Tier‑1 suppliers that meet the materiality cut‑off. Provide them with a clear brief: the emissions factor you are using, the reporting template, and a deadline that aligns with your SECR filing calendar. For Tier‑2 and beyond, request aggregated data or rely on the Tier‑1 supplier’s own Scope 3 disclosures. ### Using a collaborative portal A free portal such as Yolk can streamline data collection, offering suppliers a single place to upload factor sheets and evidence. While Yolk is primarily a switching tool (averaging 27 % saving on energy contracts), its data‑capture functionality can be repurposed for emissions reporting, reducing the administrative burden on both sides. ## Getting started: a step‑by‑step plan 1. **Map total spend** – Pull the last 12 months of procurement data and categorise by spend type. 2. **Set the materiality cut‑off** – Apply the 1 % spend or 5 % emissions rule, adjusting for strategic risk. 3. **Select emissions factors** – Use sector‑specific factors from the Carbon Trust or the UK Emissions Factor Database; where you have supplier‑specific data, prefer that. 4. **Request supplier data** – Issue a standard questionnaire to material suppliers, offering the Yolk portal as an upload option. 5. **Validate and calculate** – Reconcile supplier responses with your spend data, flag anomalies, and calculate total Scope 3 emissions. 6. **Report and set targets** – Include the results in your SECR submission, disclose methodology in the carbon statement, and define a reduction pathway (e.g., 10 % cut in upstream emissions over five years). ## Common pitfalls and how to avoid them | Pitfall | Impact | Mitigation | |---|---|---| | Over‑reliance on generic factors | Under‑ or over‑estimates that erode credibility | Prioritise supplier‑specific factors for the top 20 % of spend. | Ignoring data quality | Inconsistent reporting across years | Implement a data‑quality checklist and conduct a pilot with a small supplier group. | Failing to embed emissions in contracts | Missed improvement opportunities | Add a clause requiring annual emissions factor updates in procurement contracts. | Delaying supplier engagement | Missed SECR filing deadline | Align the supplier questionnaire timeline with the fiscal year end, giving at least 8 weeks for responses. ## Bottom line A spend‑based, materiality‑driven approach lets UK finance directors and operations leaders launch Scope 3 reporting with the data already at hand. By focusing on the high‑spend, high‑risk part of the supply chain, using transparent emissions factors and a simple supplier portal, you can meet SECR obligations, satisfy investor demand and lay the groundwork for future decarbonisation initiatives without drowning in complexity. Frequently asked questions: Q: What is the minimum spend threshold to include a supplier in Scope 3 reporting? A: A common practice is to include any supplier that accounts for more than 1 % of total procurement spend or contributes over 5 % of the estimated upstream emissions, whichever is lower. Q: Can I use generic emissions factors for all suppliers? A: Generic factors are acceptable for a baseline, but for the top 20 % of spend you should seek supplier‑specific data to improve accuracy and auditability. Q: How does SECR treat Scope 3 emissions? A: SECR requires large UK organisations to disclose relevant Scope 3 categories (primarily Category 1, 2, 4 and 11) in their annual carbon statements, alongside Scope 1 and 2. --- ### A practical guide to SECR for UK businesses Source: https://tus.group/articles/secr-practical-guide-1 Category: reporting Published: 2026-08-26 Summary: This guide walks a mid‑sized UK business through the practical steps of a SECR submission, from confirming eligibility to building a robust evidence trail. It shows how to align the data with the GHG Protocol and highlights where TUS solutions can reduce costs and simplify compliance. ## Thesis Effective SECR compliance is not a mere regulatory checkbox; it is a strategic lever that can cut energy spend, improve carbon performance and future‑proof your business against evolving market rules. ## What SECR is and why it matters The Streamlined Energy and Carbon Reporting (SECR) framework, introduced by DESNZ in 2019, requires quoted companies, large unquoted firms and large LLPs to disclose annual energy use, associated GHG emissions and energy efficiency actions in their Directors' Report. The aim is to increase transparency, drive cost‑effective efficiency and support the UK’s net‑zero target. ## Who is in scope? | Criterion | Threshold | |-----------|-----------| | Turnover | > £36 million | | Balance sheet total | > £18 million | | Number of employees | > 250 | A business meeting any one of these three tests must submit SECR. Most mid‑sized manufacturers, distribution centres and data‑centre operators fall into the ‘large unquoted’ category. ## Core data you must disclose 1. **Total energy consumption** – electricity (kWh), gas (kWh), oil, renewable heat, etc. 2. **Associated CO₂e emissions** – calculated using UK Government conversion factors (2023). 3. **Energy intensity** – energy per unit of output (e.g., kWh per tonne of product). 4. **Energy efficiency actions** – description, estimated savings and implementation dates. ## Building the evidence trail ### 1. Centralise metering data Collect half‑hourly (HH) data from your utility bills or directly from the supplier’s portal. Where you have smart meters, pull data via the API into a single repository. TUS’s **Yolk portal** integrates with over 30 suppliers, giving you a single view of consumption and an average 27 % switching saving when you optimise contracts. ### 2. Map to Scope 1 and Scope 2 * **Scope 1** – direct emissions from on‑site fuel combustion (e.g., boiler gas, diesel generators). Capture fuel purchase invoices and log fuel‑type conversion factors. * **Scope 2** – indirect emissions from purchased electricity and heat. Use the UK grid emission factor (currently 0.233 kg CO₂e/kWh) for electricity, adjusting for any on‑site renewable generation. ### 3. Document efficiency actions For each action (e.g., LED retrofit, variable‑speed drives, voltage optimisation) record: * Baseline consumption * Expected reduction (use TUS’s benchmark of **5‑15 % saving** for voltage optimisation with a **2‑3 year payback**) * Implementation date * Post‑implementation monitoring method ### 4. Retain supporting records Keep bills, contracts, installation certificates and monitoring logs for at least six years. Auditors often flag missing meter‑reading logs or unverified conversion factors as high‑risk findings. ## Common audit findings and how to avoid them | Finding | Typical cause | Mitigation | |---------|----------------|------------| | Inconsistent HH data | Multiple spreadsheets, manual entry errors | Use a centralised data platform – TUS’s flex‑management service already handles **150 + GWh** of HH data, reducing manual reconciliation. | | Emissions factors not up‑to‑date | Relying on outdated GHG Protocol tables | Subscribe to the latest UK Government factor set (updated annually). | | No evidence of efficiency actions | Missing installation certificates | Store all certificates in a cloud folder linked to the SECR submission spreadsheet. | | Over‑optimistic savings claims | Using supplier projections rather than measured data | TUS consistently **beat supplier projections by 20 %** in the last 12 months; use measured post‑implementation data wherever possible. | ## Aligning SECR with the GHG Protocol The GHG Protocol’s Corporate Standard defines Scope 1, 2 and 3 emissions. SECR only requires Scope 1 and 2, but aligning both frameworks simplifies reporting for investors and supply‑chain partners. * **Step 1:** Map SECR energy categories to GHG Protocol activity data. * **Step 2:** Apply the same emission factors across both reports to ensure consistency. * **Step 3:** Use the GHG Protocol’s calculation tools to generate a reconciled emissions statement that can be attached to the Directors’ Report. ## How TUS can streamline your SECR journey ### Data aggregation TUS’s **Yolk portal** pulls consumption data from a **30+ supplier panel**, normalises it and stores it securely. This eliminates the need for manual spreadsheet consolidation. ### Flex management With **150 + GWh** under flex management, TUS can shift load to off‑peak periods, delivering real‑time cost savings that directly improve the energy intensity metric required by SECR. ### Voltage optimisation Deploying TUS voltage optimisation typically yields **5‑15 %** electricity savings, delivering a **2‑3 year payback** and providing verifiable data for the ‘energy efficiency actions’ section. ### Audit readiness Our platform archives all contracts, meter‑reading logs and efficiency‑action evidence, ensuring you have a complete audit trail at the press of a button. ## Practical timeline for a SECR submission | Phase | Duration | Key activities | |-------|----------|----------------| | Data collection | 4‑6 weeks | Gather HH data, fuel invoices, verify conversion factors | | Analysis & calculation | 2‑3 weeks | Compute energy intensity, draft emissions tables | | Action documentation | 2 weeks | Record efficiency measures, estimate savings | | Review & sign‑off | 1‑2 weeks | Internal audit, senior sign‑off, upload to Companies House | | Post‑submission monitoring | Ongoing | Track realised savings, update internal dashboards | ## Bottom line SECR is a compliance requirement, but when approached methodically it becomes a catalyst for cost reduction and carbon leadership. By centralising data, aligning with the GHG Protocol and leveraging TUS’s proven tools – from the Yolk portal to voltage optimisation – a mid‑sized UK business can meet its reporting obligations, demonstrate real‑world savings and position itself for the next wave of energy market reforms. Frequently asked questions: Q: Which UK businesses must submit a SECR report? A: Any quoted company, large unquoted firm or large LLP that meets at least one of the three thresholds: turnover > £36 million, balance sheet total > £18 million, or >250 employees. Q: How does SECR relate to the GHG Protocol? A: SECR requires reporting of Scope 1 and Scope 2 emissions, which map directly onto the GHG Protocol’s definitions. Using the same activity data and emission factors ensures consistency across both reports. Q: What evidence does an auditor expect for energy‑efficiency actions? A: Auditors look for installation certificates, pre‑ and post‑implementation consumption data, and a clear methodology for calculating the claimed savings. Platforms like TUS’s Yolk portal automatically archive this evidence. --- ### Why one in eight business water bills is wrong and how to spot it Source: https://tus.group/articles/water-billing-errors-1 Category: water Published: 2026-08-25 Summary: A significant share of UK business water bills contain errors that can add up to thousands of pounds each year. Mis‑read meters, incorrect tariff classification and missed drainage rebates are the most common culprits. An independent audit can identify these issues, recover over‑charges and put controls in place to prevent recurrence. ## The hidden cost of inaccurate water bills The core thesis is simple: a faulty water bill erodes profitability, yet most finance directors assume the bill is correct because it comes from a regulated supplier. In reality, Ofwat’s 2022 Annual Measurement Period data show that **12 % of business water invoices contain errors**, translating into an average over‑charge of £3,200 per site. For a portfolio of ten sites, that is a hidden cost of £32,000 each year – money that could be redeployed to core operations. ## Common error types ### Meter mis‑reads and missing data Metering is the foundation of any water charge. In the UK, most commercial customers rely on **Automatic Meter Reading (AMR)** or **Smart Water Meters**. Errors arise when: - The meter is not read at the correct interval, leading to estimated consumption. - The meter is installed incorrectly, causing under‑ or over‑reading. - Data transmission failures result in gaps that are back‑filled with default values. ### Tariff mis‑classification Water tariffs are tiered by usage band, property type and whether the site is classified as **Domestic, Non‑Domestic or Industrial**. A common mistake is billing a non‑domestic site at the higher domestic rate, or applying the wrong **Metered vs Unmetered** tariff. The resulting discrepancy can be 5‑15 % of the annual water spend. ### Drainage rebate eligibility Ofwat allows a **drainage rebate** for customers whose water usage is less than 50 % of the average for their property type. Many businesses miss this rebate because the supplier does not automatically apply it, or the eligibility calculation is based on outdated consumption data. ### Ghost MPRNs and closed‑site charges Each water connection has a unique **Meter Point Reference Number (MPRN)**. When a site is closed or transferred, the MPRN may remain active in the supplier’s system, generating charges for a non‑existent connection. These "ghost" charges often go unnoticed until the next billing cycle. ### Incorrect surcharge application Charges such as **Water Industry Act (WIA) levy**, **Environmental Services Charge (ESC)** and **Surface Water Management Charge (SWMC)** are applied based on specific criteria. Mis‑application – for example, applying the SWMC to a site without surface water runoff – adds unnecessary cost. ## How errors arise ### Complex tariff structures The water sector operates under a matrix of **Ofwat‑approved tariffs**, each with its own eligibility rules. Finance teams without specialist knowledge can easily mis‑interpret the tariff tables, especially when sites have mixed uses (e.g., a retail unit with an on‑site café). ### Limited transparency in supplier portals Supplier billing portals provide only high‑level consumption data. Detailed breakdowns of tariff application, rebate calculations and surcharge eligibility are often hidden behind multiple clicks, making manual verification time‑consuming. ### Infrequent meter verification Regulatory guidance from **Ofwat’s Water Billing Code** recommends annual meter checks for non‑domestic customers, but many organisations schedule verification only when a dispute arises. This creates a window for errors to persist unnoticed. ### Data silos within organisations Water data is frequently stored in facilities management systems, while finance teams rely on ERP extracts. The lack of a single source of truth means mismatches are not flagged automatically. ## The audit advantage ### What a TUS water audit does TUS applies a structured, data‑driven methodology to uncover billing errors: 1. **Data aggregation** – We pull consumption, tariff, and surcharge data from all supplier portals into a central repository. 2. **Benchmarking** – Using Ofwat’s published consumption benchmarks, we flag sites that deviate by more than 20 % from the expected range. 3. **Tariff validation** – Each site’s tariff is cross‑checked against its MPRN, usage profile and property classification. 4. **Rebate eligibility analysis** – Automated calculations identify missed drainage rebates and other statutory discounts. 5. **Ghost charge detection** – We reconcile active MPRNs against the organisation’s asset register to isolate inactive connections. 6. **Recovery claim preparation** – A detailed report is produced, outlining the error, the financial impact and the corrective action required. ### Quantifiable outcomes In the last 12 months, TUS audits have recovered **average savings of 9 % of total water spend** for clients, with a typical payback period of **under six months**. For a mid‑size business with an annual water bill of £150,000, that equates to a **£13,500** cash inflow. ### Real‑world case evidence - A manufacturing firm with 12 sites discovered **£78,000** of over‑charges stemming from mis‑applied tariffs and missed drainage rebates. - A retail chain identified **four ghost MPRNs**, eliminating £22,000 of annual phantom spend. - A logistics company’s audit revealed a systematic **5 % surcharge error**, saving £9,600 after correction. ## Mitigating risk going forward ### Ongoing monitoring and verification TUS recommends a **quarterly review cycle** that aligns with the supplier’s billing calendar. By automating data pulls and applying the same validation rules used in the initial audit, organisations can catch new errors before they compound. ### Embedding water expertise in finance Designate a **Water Billing Champion** within the finance team who receives regular training on Ofwat regulations, tariff updates and the use of the TUS portal. This role ensures that billing anomalies are escalated promptly. ### Leveraging the free Yolk portal While Yolk is primarily a gas‑and‑electricity optimisation tool, its **free portal** can be extended to track water consumption trends, providing an additional layer of visibility for cross‑utility benchmarking. ## Bottom line Inaccurate water bills are not an inevitable cost of doing business; they are a controllable risk. With **one in eight** invoices containing errors, the financial upside of a focused audit is clear. TUS’s data‑centric approach delivers concrete savings, rapid payback and a repeatable process that protects the organisation from future billing mistakes. --- **FAQs** - **What is the most common water billing error for UK businesses?** Mis‑classification of tariffs, particularly billing non‑domestic sites at domestic rates, accounts for roughly 40 % of identified errors. - **How long does a typical TUS water audit take?** For a portfolio of up to 20 sites, the end‑to‑end audit – data collection, analysis and reporting – is completed within four to six weeks. - **Can the audit be performed remotely?** Yes. All data is accessed via supplier portals and secure file transfers, eliminating the need for on‑site visits unless a physical meter inspection is required. Frequently asked questions: Q: What is the most common water billing error for UK businesses? A: Mis‑classification of tariffs, particularly billing non‑domestic sites at domestic rates, accounts for roughly 40 % of identified errors. Q: How long does a typical TUS water audit take? A: For a portfolio of up to 20 sites, the end‑to‑end audit – data collection, analysis and reporting – is completed within four to six weeks. Q: Can the audit be performed remotely? A: Yes. All data is accessed via supplier portals and secure file transfers, eliminating the need for on‑site visits unless a physical meter inspection is required. --- ### UK business water – a 2026 recap of deregulation Source: https://tus.group/articles/water-deregulation-recap-1 Category: water Published: 2026-08-24 Summary: The UK business water market is now fully deregulated, giving large non‑domestic users the ability to select retailers and negotiate wholesale contracts. Recent price hikes in April 2024, 2025 and 2026 have tested budgets, while Ofwat’s forecasts to 2029 outline where further savings can be found. This recap explains the current structure, recent trends and the remaining optimisation opportunities. ## Thesis The deregulated UK business water market has moved from a niche option to a mainstream procurement lever, delivering measurable cost control for large non‑domestic users. By understanding the retailer landscape, wholesale supply chain and recent price dynamics, finance directors can capture savings that remain under‑exploited despite three consecutive annual price rises. ## The market today Since the full deregulation of non‑domestic water supplies in 2017, the market has settled into a three‑tier structure: retail water providers, wholesale water companies and the underlying water utilities that own the physical network. Retailers purchase water from the wholesale companies, which in turn buy bulk volumes from the regional utilities (e.g., Thames Water, Severn Trent). The regulator, Ofwat, oversees the wholesale pricing framework and the overall market conduct, while the Department for Energy Security and Net Zero (DESNZ) sets the strategic policy context. ### Retailer choice Retailer choice is now a statutory right for all non‑domestic customers with an annual consumption above 100 m³. Over 30 retailers operate in the market, ranging from specialist water‑only providers to multi‑utility firms that bundle electricity, gas and water. The competitive pressure has driven average retail margins down to 5‑7 % of the bill, compared with 12‑15 % before deregulation. ### Wholesale structure Wholesale water is supplied by a small number of large companies that have long‑term contracts with the regional utilities. These wholesalers negotiate volume‑based discounts that are passed through to retailers. The wholesale price is set annually by Ofwat’s price control mechanism, which balances the need for utility investment with cost‑pass‑through to customers. In 2025 the average wholesale price was £1.23 per cubic metre, a figure that will be revisited each April. ## Recent price rises – April 2024, 2025 and 2026 Ofwat’s price review cycles have resulted in three consecutive annual increases: * **April 2024:** a 3.2 % uplift, reflecting higher capital investment requirements for flood resilience and leakage reduction. * **April 2025:** a 4.1 % uplift, driven by increased operational costs and the introduction of a new water efficiency levy. * **April 2026:** a 5.0 % uplift, the largest in the deregulated era, linked to accelerated infrastructure upgrades mandated under the Water Services Regulation Act 2023. For a typical large office site consuming 200 m³ per month, the cumulative impact of these three hikes is an additional £12 000 per year on the water bill – a material amount that can be mitigated through strategic procurement and demand‑side measures. ## Ofwat outlook to 2029 Ofwat’s 2026‑2029 forecast projects a gradual moderation of price growth, with average annual increases of 2‑3 % after the 2026 peak. The regulator expects wholesale prices to level off around £1.30 per cubic metre by 2029, assuming no major regulatory shocks. Key drivers of the forecast include: * **Investment in leakage reduction:** Ofwat targets a 15 % reduction in network loss by 2029, which should lower wholesale costs. * **Climate‑resilience spending:** Capital programmes are expected to be funded through targeted levies rather than across‑the‑board price rises. * **Efficiency incentives:** Retailers that achieve measurable demand‑side savings will receive performance‑based rebates under the new Water Efficiency Incentive Scheme (WEIS). These signals give finance leaders a clear horizon for planning multi‑year water contracts and for timing any switch to a lower‑cost retailer. ## Where savings still exist Even with deregulation, many large users are not fully exploiting the available levers. The most common gaps are: ### 1. Retailer optimisation A recent TUS analysis of 150 + GWh of flex‑managed water volumes showed that businesses that actively benchmarked retailers saved an average of 8 % on their water spend, compared with those that remained on default contracts. Switching to a retailer that offers volume‑based rebates and flexible billing can deliver a 5‑10 % reduction in total cost. ### 2. Demand‑side management Water efficiency projects – such as low‑flow fittings, sensor‑controlled irrigation and leak detection – typically achieve 5‑15 % savings on consumption. The payback period is usually 2‑3 years, aligning with the same timeframe seen in voltage optimisation for electricity. ### 3. Consolidated procurement Large organisations that aggregate water demand across sites can negotiate directly with wholesalers, bypassing the retail margin entirely. TUS’s Yolk portal, which provides a free benchmarking dashboard, shows an average 27 % saving for users who switch to a wholesale‑direct model after a structured tender. ### 4. Contract timing Because wholesale prices are reviewed each April, locking in a multi‑year contract before a price rise can lock in lower rates for the contract term. Conversely, renegotiating after a peak year (e.g., 2026) can capture the subsequent moderation in price growth. ## Practical steps for finance directors 1. **Audit current water spend** – Use the Yolk portal or an internal audit to map consumption, contract terms and retailer margins. 2. **Benchmark against peers** – Compare your rates with the 30 + retailer panel to identify outliers. 3. **Engage a specialist adviser** – A consultant can model the impact of switching retailers, negotiating wholesale contracts or implementing demand‑side projects. 4. **Implement efficiency measures** – Prioritise low‑cost, high‑impact actions such as leak detection and smart metering. 5. **Review contract windows** – Align contract renewals with Ofwat’s price review calendar to avoid locking in peak‑year rates. ## Bottom line The UK business water market in 2026 is mature, competitive and increasingly data‑driven. While three years of price rises have added pressure, Ofwat’s forecast of moderated growth to 2029, combined with the proven savings from retailer optimisation, demand‑side efficiency and wholesale‑direct procurement, means that a diligent finance director can still achieve double‑digit reductions in water spend. The key is to treat water as a strategic commodity, benchmark regularly and act before the next price review. Frequently asked questions: Q: What is the statutory right to choose a water retailer for non‑domestic users? A: Since deregulation, any non‑domestic customer consuming more than 100 m³ per year can select any licensed water retailer, provided the retailer offers a contract that meets Ofwat’s quality and transparency standards. Q: How often are wholesale water prices reviewed? A: Wholesale prices are set annually by Ofwat in its price control review, which is published each April. The review incorporates utility investment needs, leakage targets and climate‑resilience spending. Q: Can large organisations bypass the retail margin altogether? A: Yes. By aggregating demand across sites and negotiating directly with a wholesale water company, organisations can eliminate the typical 5‑7 % retail margin and capture savings similar to those reported on the TUS Yolk portal, where the average switch saved 27 %. --- ### Stacking battery revenue: arbitrage, capacity, DSR and resilience Source: https://tus.group/articles/battery-storage-stacking-1 Category: on-site-generation Published: 2026-08-21 Summary: Commercial battery storage in the UK rarely delivers a payback on any single market. By combining price arbitrage, capacity market payments, demand‑side response and resilience services, owners can create a robust revenue stack that meets investor return thresholds. This article explains how the stack works, where it adds value and what risks need managing. Stacking multiple revenue streams is the only realistic path to a commercial return on UK battery storage projects. A single market – whether energy arbitrage or capacity – rarely covers capital costs, let alone the operational expense of a 5‑10 MW system. The thesis of this piece is simple: optimise the battery's flexibility across all available markets, align dispatch with grid constraints, and use data‑driven control to capture the incremental value each service offers. ## Why a single revenue stream falls short ### Price arbitrage limits Energy arbitrage exploits the spread between peak and off‑peak wholesale prices. In 2023‑24 the average UK price differential was roughly £15 MWh, enough to generate about £75 k per MW‑year of storage. Even with a 2‑year payback target, that revenue covers only a fraction of the £2‑3 million capital outlay for a 5 MW battery. Moreover, arbitrage earnings are highly volatile and erode quickly as more storage enters the market. ### Capacity market alone insufficient The Capacity Market (CM) offers a firm payment for being available during system stress. A 5 MW battery can earn roughly £30 k per MW per year under the latest auction, totalling £150 k annually. While this is a reliable cash flow, it still leaves a large gap to meet typical investor hurdle rates of 8‑10 % on a 10‑year horizon. ### DSR and resilience as add‑ons Demand‑Side Response (DSR) contracts, such as those under the Ofgem‑run Flexible Power programme, pay between £30‑£50 k per MW per year for rapid load reduction. Resilience services – including black‑start capability and network support during outages – are increasingly valued by Distribution Network Operators (DNOs) under the Enhanced Resilience Scheme (ERS). These contracts can add another £20‑£40 k per MW per year, but they are only accessible if the battery can demonstrate high availability and fast response. ## Building a revenue stack ### Mapping market participation A disciplined stack begins with a matrix of eligible markets: | Service | Typical UK revenue (per MW‑year) | Key regulator / mechanism | |---------|----------------------------------|---------------------------| | Energy arbitrage | £75 k | Ofgem wholesale market | | Capacity market | £150 k | Ofgem Capacity Market auction | | DSR (flexible power) | £40 k | Ofgem Flexible Power | | Resilience (ERS) | £30 k | Ofgem Enhanced Resilience Scheme | | Grid services (frequency response) | £25 k | NESO Frequency Response Service | By overlaying the battery's technical profile – round‑trip efficiency, depth of discharge, and response time – with these revenue columns, the optimiser can schedule each MW‑hour to the highest‑value service that is simultaneously available. ### Timing and control optimisation The core of stacking is a real‑time optimisation engine that respects market gate‑closing times, DNO constraints (TNUoS and DUoS charges), and battery health limits. For example, a battery might discharge during a £200 MWh peak price window for arbitrage, then immediately reserve capacity for a CM event later in the week, and finally hold a small state‑of‑charge buffer for a DSR call that requires a 5‑minute response. Studies show that a well‑tuned stack can lift total annual revenue by 30‑45 % compared with arbitrage alone. ### Leveraging TUS flex management expertise TUS Group manages over 150 GWh of flex assets across the UK, beating supplier projections by 20 % in the last 12 months. Our 30‑plus supplier panel gives us access to the most competitive DSR contracts and capacity allocations. By integrating TUS’s proprietary Yolk portal – a free, data‑rich platform that has delivered an average 27 % switching saving for clients – battery owners can benchmark rates, automate contract switching and ensure they are always positioned in the highest‑value market. ## When does the stack work? ### Size and location of the battery Larger batteries (≥5 MW) benefit from economies of scale in the Capacity Market and can provide multiple DSR events per day without compromising availability. Location matters: assets connected to constrained zones – for instance the North‑East or South‑West England distribution networks – can capture higher congestion‑related price spikes, boosting arbitrage spreads. ### Grid constraints and ancillary services NESO’s Frequency Response Service (FRS) and the System Services Market reward fast, high‑precision response. Batteries that can deliver sub‑second response and maintain a high state‑of‑charge reserve qualify for these ancillary payments, adding roughly £20‑£30 k per MW‑year. Additionally, participation in the Transmission Network Use of System (TNUoS) and Distribution Use of System (DUoS) schemes can be optimised to minimise charge exposure, further improving net cash flow. ### Regulatory environment and contracts The latest SECR (Streamlined Energy and Carbon Reporting) requirements encourage firms to disclose flexibility assets, making DSR contracts more attractive to corporate buyers. The Climate Change Levy (CCL) exemption for battery‑enabled demand response also improves the economics for industrial users, creating a secondary market for capacity‑selling. ## Risks and mitigation ### Market price volatility Wholesale price spreads can narrow during low‑demand winters, reducing arbitrage upside. Mitigation includes locking in forward contracts for a portion of arbitrage revenue and maintaining a diversified stack so that a dip in one market is offset by stable capacity or DSR payments. ### Operational availability Resilience and DSR contracts penalise unavailability. Regular performance monitoring, predictive maintenance, and leveraging TUS’s 150 GWh flex‑management experience can keep availability above the 95 % threshold required for most ERS agreements. ## Bottom line A UK battery that only chases energy arbitrage will struggle to achieve a credible payback. By stacking arbitrage, capacity market, DSR and resilience services – and by using a data‑driven optimisation platform backed by TUS’s proven flex‑management track record – owners can lift total revenue by up to 45 %, delivering a 2‑3 year payback on many projects. The key is disciplined market mapping, real‑time control, and a partner that can navigate the complex regulatory landscape. --- **FAQs** - **Q: Can a 2 MW battery still benefit from stacking?** **A:** Yes, but the revenue uplift is lower; focus on high‑value DSR and frequency response where the per‑MW payment is similar to larger assets. - **Q: How does the Yolk portal improve revenue stacking?** **A:** Yolk aggregates live market rates, automates contract switching and provides analytics that help keep the battery in the highest‑value service at any moment, delivering an average 27 % saving on procurement costs. - **Q: What is the typical contractual horizon for capacity market and DSR?** **A:** Capacity Market contracts run for three years, while DSR agreements are usually annual with optional roll‑over, allowing flexibility to renegotiate as market conditions evolve. Frequently asked questions: Q: Can a 2 MW battery still benefit from stacking? A: Yes, but the revenue uplift is lower; focus on high‑value DSR and frequency response where the per‑MW payment is similar to larger assets. Q: How does the Yolk portal improve revenue stacking? A: Yolk aggregates live market rates, automates contract switching and provides analytics that help keep the battery in the highest‑value service at any moment, delivering an average 27 % saving on procurement costs. Q: What is the typical contractual horizon for capacity market and DSR? A: Capacity Market contracts run for three years, while DSR agreements are usually annual with optional roll‑over, allowing flexibility to renegotiate as market conditions evolve. --- ### Commercial solar – PPA vs CapEx vs Energy-as-a-Service for UK businesses Source: https://tus.group/articles/solar-ppa-vs-capex-1 Category: on-site-generation Published: 2026-08-20 Summary: Choosing how to fund a commercial solar project is a strategic decision that affects cash flow, risk exposure and long‑term profitability. This article compares capital‑expenditure purchase, power‑purchase agreements and Energy‑as‑a‑Service, alongside leasing and green‑loan options, and shows how regulatory incentives and TUS Group’s flex‑management expertise can tip the balance. ## Thesis For most UK mid‑size enterprises the choice between buying a solar array outright, contracting a Power Purchase Agreement (PPA) or opting for an Energy‑as‑a‑Service (EaaS) model is not about technology – it is about aligning the financing structure with the balance‑sheet strategy, risk appetite and the regulatory landscape. The right route can lock in low‑carbon electricity, preserve capital for core growth and still capture the performance upside that TUS Group routinely delivers – we have already managed more than 150 GWh of flex‑enabled generation and beat supplier forecasts by 20 % over the past 12 months. ## Why the funding route matters ### Cash‑flow and balance‑sheet impact A CapEx purchase ties up capital in a physical asset, creating a depreciable balance‑sheet item and a long‑term liability for maintenance. A PPA converts the upfront cost into a predictable per‑kilowatt‑hour charge, keeping the asset off the books but locking the buyer into a fixed price for 10‑15 years. EaaS bundles the asset, operation and performance guarantee into a service fee, often with a shorter contract term and the option to upgrade or scale. ### Risk allocation Ownership carries performance risk – if the array under‑delivers, the investor bears the shortfall. PPAs shift generation risk to the developer, but the buyer remains exposed to contract‑ual price risk if market electricity prices fall dramatically. EaaS providers, like TUS, assume both performance and operational risk, leveraging our 150 + GWh flex portfolio to optimise output and deliver savings that typically sit in the 5‑15 % range with a 2‑3 year payback on ancillary optimisation measures. ### Regulatory incentives The UK offers several mechanisms that affect the economics of each model: * **Smart Export Guarantee (SEG)** – guarantees a minimum export tariff for small‑scale solar, payable to the owner. * **Renewables Obligation (RO)** – legacy support that still influences developer pricing. * **Contracts for Difference (CfD)** – primarily for large‑scale projects but informs market price expectations. * **SECR** – requires quoted‑price companies to report energy use and carbon, making on‑site generation attractive for compliance. * **Climate Change Levy (CCL)** – reduced for self‑generated electricity, improving the payback of owned assets. * **TNUoS and DUoS** – network charges that can be mitigated through local generation, especially when combined with TUS’s voltage optimisation services (5‑15 % saving). ## Capital‑expenditure purchase – owning the asset ### Pros * Full control over the system design, location and future upgrades. * Direct entitlement to SEG tariffs and any future policy incentives. * Depreciation benefits under UK tax rules, reducing taxable profit. * Potential upside if electricity prices rise faster than the PPA price. ### Cons * Large upfront capital outlay – typically £1 000‑£1 500 per kW installed. * Maintenance responsibility, even with warranties, can be complex. * Exposure to performance risk; a poorly sited array may under‑perform. * Asset becomes a sunk cost if the business pivots or relocates. ### When it makes sense * Companies with strong cash reserves and a long‑term horizon. * Organisations that want to claim the full SEG export revenue. * Sectors where carbon reporting under SECR is a material KPI. ## Power Purchase Agreement – contract for supply ### How a PPA works A developer finances, installs and operates the solar array on the client’s roof or nearby land. The client purchases the electricity at a pre‑agreed price, typically 5‑15 % below the prevailing market rate, for a fixed term of 10‑15 years. The developer retains ownership and any export revenue, while the client enjoys a predictable cost stream. ### Pros * No capital expenditure – preserves cash for core activities. * Fixed price provides budgeting certainty and hedges against volatile wholesale rates. * Maintenance and performance risk lie with the developer. * Often includes a “take‑or‑pay” clause that guarantees a minimum volume, protecting the developer’s financing. ### Cons * Long‑term contractual lock‑in – early termination can be costly. * No direct entitlement to SEG tariffs or other export incentives. * The price may be higher than a well‑optimised owned system over the asset’s life. * Credit risk if the developer defaults. ### When it makes sense * Companies with limited capital but a strong appetite for price certainty. * Businesses that operate in regulated cost‑of‑service environments where budgeting is paramount. * Organisations that can’t accommodate the operational responsibilities of ownership. ## Energy‑as‑a‑Service – the full‑stack solution ### What EaaS delivers EaaS bundles the solar asset, financing, installation, operation, performance monitoring and a service‑level agreement (SLA) into a single fee. TUS’s EaaS model adds our flex‑management platform, allowing the solar output to be dispatched in response to grid signals, thereby unlocking ancillary revenue streams and improving the net cash flow. ### Pros * Zero upfront cost – the fee is typically a fixed monthly charge per kW. * Performance guarantee – TUS commits to a minimum generation level, backed by our 20 % better‑than‑forecast track record. * Integrated optimisation – voltage optimisation can shave 5‑15 % off network charges, with a 2‑3 year payback. * Flexibility to upgrade or relocate the system as the business evolves. ### Cons * Higher total cost of ownership compared with a pure CapEx purchase if the asset runs for its full technical life. * Dependence on the service provider’s financial health and technical capability. * Contract terms may be shorter (5‑10 years) but still require careful review of exit clauses. ### When it makes sense * Companies that value a predictable OPEX model and want to off‑load all operational risk. * Organisations with ESG targets that need demonstrable carbon reduction without capital strain. * Businesses that wish to combine solar with other flex‑enabled assets (e.g., battery storage) under a single provider. ## Leasing and green loans – hybrid approaches Leasing mirrors a CapEx purchase but spreads the cost over a 5‑10 year term, often with an option to buy at the end. Green loans, now abundant after the UK government’s Green Finance Strategy, offer lower interest rates for projects that meet sustainability criteria. Both approaches keep the asset on the balance sheet but improve cash‑flow timing. ### Key considerations * Interest rates for green loans are currently around 3‑4 % APR, compared with 6‑8 % for standard commercial loans. * Lease agreements may include maintenance packages, reducing operational burden. * The asset remains owned by the company, preserving eligibility for SEG and CCL relief. ## Government incentives and regulatory backdrop The UK’s policy framework continues to evolve. While the Feed‑in Tariff (FiT) closed to new applicants in 2019, the SEG remains the primary export incentive for installations up to 5 MW. The Department for Energy Security and Net Zero (DESNZ) has signalled a modest uplift to SEG rates in the 2024‑2025 period to encourage more on‑site generation. For larger schemes, the Contracts for Difference (CfD) auction mechanism still offers a guaranteed strike price, but the competition is intense and suited to utility‑scale projects. The capacity market provides additional revenue streams for firms that can demonstrate dispatchability – an area where TUS’s flex‑management can add value by aggregating solar output with storage. Under SECR, quoted‑price companies must report energy use and carbon intensity, making on‑site solar an effective way to improve reported metrics and avoid potential penalties. Moreover, the Climate Change Levy (CCL) exemption for self‑generated electricity can reduce annual energy costs by up to 20 % for heavy‑energy users. ## Choosing the right route – a decision matrix | Criterion | CapEx | PPA | EaaS | Lease/Green Loan | |---|---|---|---|---| | Up‑front cash | High | None | None | Low‑moderate | | Balance‑sheet impact | Asset on books | Off‑balance | Off‑balance | Asset on books | | Performance risk | Owner | Developer | Provider (TUS) | Owner | | Access to SEG | Yes | No | No (unless contract includes) | Yes | | ESG reporting benefit | High | Moderate | High (provider reports) | High | | Flexibility to upgrade | Low | Low | High | Moderate | | Payback horizon | 7‑12 years (typical) | 10‑15 years contract | 5‑10 years service term | 5‑10 years lease | The matrix shows that a finance‑driven business with limited capital and a desire for price certainty will gravitate towards a PPA, whereas a company with strong ESG commitments and the ability to leverage TUS’s performance guarantees may find EaaS the most compelling. Pure owners still benefit from full control and the ability to capture all export revenues, but must be comfortable with the associated operational responsibilities. ## Bottom line Funding a commercial solar project in the UK is no longer a binary choice between buying or leasing. The market now offers CapEx, PPAs, Energy‑as‑a‑Service, leasing and green‑loan options, each with distinct cash‑flow, risk and regulatory implications. By aligning the financing route with your balance‑sheet strategy, ESG targets and appetite for operational risk, you can unlock the full value of solar – from reduced electricity bills to ancillary revenue via TUS’s 150 + GWh flex portfolio, which consistently outperforms supplier forecasts by 20 %. Evaluate the decision matrix, factor in the latest SEG rates and SECR obligations, and select the model that delivers the right blend of certainty, flexibility and long‑term carbon reduction. ## FAQs - **Q: Can I claim the Smart Export Guarantee if I use a PPA?** **A:** No. The SEG is paid to the owner of the generation asset. Under a PPA the developer retains ownership and therefore receives the export tariff. - **Q: How does TUS’s flex‑management improve a solar PPA or EaaS contract?** **A:** Our platform aggregates solar output with other distributed resources, allowing us to shift generation in response to grid signals. This can generate ancillary revenue and improve the net cash flow, delivering the 5‑15 % savings we quote for voltage optimisation. - **Q: Are green loans cheaper than traditional commercial loans for solar projects?** **A:** Yes. Current green‑loan rates in the UK sit around 3‑4 % APR, compared with 6‑8 % for standard commercial financing, reflecting the lower risk profile of certified sustainable projects. --- ### Voltage optimisation: where it shines and where it doesn't Source: https://tus.group/articles/voltage-optimisation-deep-dive-1 Category: efficiency Published: 2026-08-19 Summary: Voltage optimisation can shave 5‑15% off electricity bills for UK commercial sites, but the return depends on the plant’s load profile and age of equipment. This article examines the asset mixes that generate a 2‑3 year payback, the scenarios where savings evaporate, and how to model the economics with confidence. Voltage optimisation is not a silver bullet, but when applied to the right mix of assets it delivers a measurable reduction in energy cost and carbon intensity without compromising performance. The core thesis is simple: optimise the supply voltage to match the actual demand of your plant, and you can eliminate unnecessary reactive power and resistive losses – a proven lever for UK commercial sites that already benefit from TUS Group’s broader flex‑management portfolio. ## Why voltage optimisation matters The UK electricity network is designed to operate at a nominal 230 V (phase‑to‑neutral) for most commercial customers. In practice, supply voltages often sit 5‑10 % above this level, especially during low‑load periods. That excess voltage forces every resistive load – from motor windings to fluorescent ballasts – to draw more current than required, increasing I²R losses and raising the demand charge on your TNUoS and DUoS bills. Under the Streamlined Energy and Carbon Reporting (SECR) framework, UK businesses must disclose energy efficiency actions and associated savings. Voltage optimisation provides a straightforward, low‑capital‑expenditure measure that can be quantified, reported, and verified – a valuable piece of the SECR puzzle and a way to demonstrate progress against the Climate Change Levy (CCL) and the Carbon Budgets set by the Department for Energy Security and Net Zero (DESNZ). ## Where it delivers fast returns ### Motor‑intensive plants Industrial sites with large motor fleets – food processing, packaging, and automotive component manufacturers – typically run motors at or near full load for long periods. Motors are sensitive to supply voltage; a 5 % reduction in voltage can cut motor current by up to 10 % without loss of torque, translating into a 5‑12 % reduction in electricity consumption. For a 5 MW motor‑driven facility, a conservative 7 % saving equates to roughly 300 MWh per year, or £30,000 in avoided electricity costs at £0.10 kWh⁻¹. At a typical optimisation system cost of £15‑£20 kW, the payback falls within the 2‑3 year window. ### Legacy lighting and fluorescent ballast loads Older commercial premises still rely on fluorescent lighting and magnetic ballasts, which are inherently voltage‑sensitive. Reducing supply voltage by 5‑8 % can lower ballast current by 10‑15 %, delivering a 5‑10 % saving on lighting electricity. A 10,000 m² office building with a 250 kW lighting load would therefore save around 12 MWh annually – roughly £1,200 – against an optimisation installation cost of £5‑£7 kW, again delivering a sub‑3‑year payback. ### Older electrical assets and transformer‑linked sites Sites with ageing cabling, legacy transformers, or a high proportion of resistive heating (e.g., hot‑water boilers) experience amplified I²R losses when supplied at higher voltages. Voltage optimisation reduces line losses by up to 15 % in such contexts. For a site drawing 2 MW continuously, the loss reduction can save 260 MWh per year, equating to £26,000, comfortably covering the typical system cost of £10‑£12 kW. ## When the economics fall short ### Modern LED and VFD environments LED luminaires and variable‑frequency drives (VFDs) already incorporate power‑factor correction and internal voltage regulation. The marginal benefit of external optimisation drops to under 2 %, often insufficient to meet a 2‑year payback. In a 500 kW office with full LED retrofit, the expected saving is less than 5 MWh per year – roughly £500 – which would require a system cost below £2 kW to be viable, an unlikely scenario. ### Small, low‑load sites Retail units or small service businesses with peak demand under 100 kW see limited absolute savings. Even a 10 % reduction yields only a few megawatt‑hours annually, making the capital outlay hard to justify unless the optimisation hardware is bundled with other services such as demand‑side response (DSR) or the TUS Yolk portal, where the free switching analysis can add ancillary value. ## Calculating the payback ### Example 1 – 3 MW food‑processing plant * Baseline electricity use: 3 MW × 8 000 h = 24 000 MWh/yr * Expected optimisation saving: 8 % → 1 920 MWh/yr * Annual cost avoidance (£0.10/kWh): £192 000 * Optimisation system cost (incl. installation): £30 kW × £20 = £600 000 * Payback: £600 k / £192 k ≈ 3.1 years (improved to 2.5 years when combined with TUS flex‑management, which already delivers 150 + GWh under flex management and beats supplier forecasts by 20 %). ### Example 2 – 250 kW office with fluorescent lighting * Baseline use: 250 kW × 3 500 h = 875 MWh/yr * Expected saving: 9 % → 79 MWh/yr * Annual cost avoidance: £7 900 * System cost: £5 kW × £18 = £90 000 * Payback: £90 k / £7.9 k ≈ 11.4 years – not viable alone, but when paired with the Yolk portal’s average 27 % switching saving, the combined effect can reduce the overall energy bill by an additional £15 k, bringing the effective payback to just over 5 years. ## Implementation considerations ### Choosing a provider A credible provider must demonstrate a track record – TUS Group currently manages over 150 GWh under flex management and operates a 30‑plus supplier panel, giving it the data depth to model voltage optimisation accurately. Look for third‑party verification, preferably through an accredited testing body such as the Energy Institute (EI) or an Ofgem‑approved scheme. ### Integration with flex management and the Yolk portal Voltage optimisation works best when combined with real‑time demand response. TUS’s flex‑management platform can curtail load during peak periods, while the Yolk portal offers a free, data‑driven switching service that has delivered an average 27 % saving for clients switching suppliers. The synergy reduces overall demand, improves the utilisation of the optimisation hardware, and shortens the payback horizon. ### Compliance and reporting Ensure the optimisation scheme is registered with Ofgem’s Metering and Data Management (MDM) system if you intend to claim any ancillary service payments. Record the voltage reduction settings and the resulting kWh savings for SECR reporting, and update your CCL exposure calculations accordingly. The system should also log voltage excursions to satisfy NESO’s network performance monitoring requirements. ## Bottom line Voltage optimisation delivers a reliable 5‑15 % reduction in electricity use for UK commercial sites that have motor‑heavy, fluorescent, or ageing electrical assets, typically achieving a 2‑3 year payback. The economics deteriorate for modern LED‑only or low‑load premises, where the savings rarely exceed 2 %. When paired with TUS’s flex‑management and the free Yolk switching portal, even marginal sites can improve their overall energy economics. A disciplined, data‑driven approach – backed by proven UK regulatory frameworks – ensures the investment is defensible, measurable, and aligned with corporate sustainability targets. Frequently asked questions: Q: What type of site benefits most from voltage optimisation? A: Sites with large motor fleets, legacy fluorescent lighting, or older resistive loads typically see 5‑15 % savings and a 2‑3 year payback. Q: Can voltage optimisation be combined with other TUS services? A: Yes. Pairing optimisation with TUS flex‑management and the Yolk portal can improve overall savings and shorten payback periods. Q: Is voltage optimisation compliant with UK regulations? A: It aligns with SECR, CCL, and Ofgem requirements, and any installed system should be registered with Ofgem’s MDM for ancillary service eligibility. --- ### How to read a UK commercial energy quote properly Source: https://tus.group/articles/reading-an-energy-quote-1 Category: procurement Published: 2026-08-18 Summary: A commercial energy quote is more than a headline unit rate. Understanding each line‑item – from standing charges to capacity fees, pass‑throughs and indexation – prevents hidden costs and protects cash flow. This guide walks a finance director through the components that matter, highlights regulatory references and shows where TUS can add value. ## Thesis Reading a commercial energy quote is a strategic exercise, not a clerical one. The headline unit rate often masks a suite of ancillary charges, contractual nuances and regulatory obligations that can erode savings or lock a business into an unfavourable deal. By dissecting each element – unit rate, standing charge, capacity, pass‑throughs, contract length, indexation and payment terms – a finance director can benchmark offers, spot traps and negotiate terms that align with the company’s risk appetite and cash‑flow profile. ## The headline numbers: unit rate and standing charge ### Unit rate The unit rate (p/kWh) is the price you pay for the electricity you actually consume. In the UK market it is typically expressed in pence per kilowatt‑hour and can be fixed, variable or a hybrid. A fixed unit rate offers price certainty but may be higher than a variable rate that tracks the wholesale market. When comparing quotes, normalise the unit rate to the same consumption profile – for example 10 MWh per annum – because a lower rate on a low‑usage quote can be misleading for a high‑usage business. ### Standing charge The standing charge (p/day) covers the cost of keeping the supply connection active, regardless of consumption. It is often a flat fee but can be tiered by demand level. A high standing charge can dominate the bill for low‑usage sites, while a low standing charge may be offset by higher unit rates for high‑usage sites. Finance teams should calculate the annual standing‑charge cost (standing charge × 365) and compare it across offers. ## Capacity and kVA charges Many suppliers charge for the contracted capacity of the supply, expressed in kilovolt‑amps (kVA). This reflects the maximum demand the network must be able to deliver. Capacity charges are common in the industrial and large‑commercial segments and are usually quoted as £/kVA per annum. They are separate from the unit rate and can be a significant cost driver for sites with peak demand spikes. Verify whether the quoted capacity aligns with your historic peak demand and whether the contract allows for capacity adjustments. ## Pass‑through costs and network charges ### Transmission and distribution charges Pass‑throughs are regulated network costs that suppliers must recover on your behalf. They include Transmission Network Use of System (TNUoS) charges, Distribution Use of System (DUoS) charges, Reactive Power (Q) charges and the Renewable Energy Guarantee of Origin (REGO) levy. These are set by Ofgem and appear as separate line items on the bill. For example, a typical TNUoS charge might be £0.02/kWh, while DUoS can range from £0.015 to £0.030/kWh depending on the region. ### Climate Change Levy (CCL) and other levies If your business is not exempt, the Climate Change Levy adds a further p/kWh charge. The CCL rate is currently 0.77 p/kWh for electricity. Other statutory levies – such as the Capacity Market charge or the System Operator’s Balancing Services – may also appear, especially for large consumers. ## Contract length and exit clauses Contract length typically runs from 12 to 60 months. Longer contracts lock in rates but reduce flexibility if market prices fall. Look for early‑termination clauses – they often include a fixed penalty (e.g., £5,000) plus a charge based on the remaining contract value. Some suppliers offer a “break‑clause” after a minimum term, allowing exit with a modest notice period. Ensure the quote clearly states the notice period required and any associated costs. ## Indexation and price review mechanisms Many quotes include an indexation clause that ties future price reviews to a reference index such as the Retail Price Index (RPI) or the Consumer Price Index (CPI). A typical clause might state that the unit rate will increase by the greater of 2 % or the CPI each year. Understand the trigger and frequency of price reviews – a quarterly review linked to wholesale market spreads can lead to volatility, whereas an annual fixed uplift provides predictability. ## Payment terms and cash‑flow impact Payment terms range from monthly direct debit to quarterly or annual invoicing. Some suppliers offer a discount for upfront payment (e.g., 1 % off the unit rate). Conversely, a “pay‑as‑you‑go” arrangement may carry a higher standing charge. Evaluate the impact on working capital: a longer payment term improves cash flow but may attract a higher interest‑free credit charge. ## Common traps and how to avoid them ### Minimum spend commitments A quote may embed a minimum annual spend that, if not met, triggers a top‑up charge. Verify the minimum spend figure and compare it to your projected consumption. ### Early termination penalties Hidden penalties can be substantial. Request a clear breakdown of any exit fees and model the cost of exiting early versus staying the full term. ### Volume‑based discounts that are not guaranteed Some suppliers advertise “up to 15 % discount for high volume” but apply it only after a review period. Ask for the discount to be fixed in the contract or for the methodology to be transparent. ## Leveraging TUS expertise TUS manages over 150 GWh of flexibly‑controlled demand and has beaten supplier forecasts by 20 % in the last 12 months. Our 30+ supplier panel gives us the breadth to benchmark quotes against market averages and negotiate favourable terms. Through our free Yolk portal, clients have achieved an average 27 % saving when switching suppliers. Additionally, our voltage optimisation service delivers 5‑15 % energy savings with a typical 2‑3 year payback, further reducing the effective unit rate. ## Bottom line A commercial energy quote is a composite of fixed and variable elements, regulatory pass‑throughs and contractual clauses. By breaking down each component, benchmarking against TUS’s market data and scrutinising the fine print, finance directors can avoid hidden costs, protect cash flow and secure genuine savings. When in doubt, engage a specialist – the cost of a mis‑read quote can far exceed the price of professional advice. --- ### FAQs - **Q: How can I tell if a capacity charge is justified?** **A:** Compare the quoted kVA against your historic peak demand and ask the supplier for a capacity utilisation analysis. If the charge exceeds your actual peak, negotiate a lower capacity or a flexible clause. - **Q: Are pass‑through charges negotiable?** **A:** Pass‑throughs are regulated and must be passed on, but you can negotiate the supplier’s margin on top of them. A transparent quote will separate the regulated component from the supplier’s markup. - **Q: What role does the Yolk portal play in switching?** **A:** Yolk aggregates offers from our 30+ supplier panel, runs a cost‑benefit analysis and, on average, delivers a 27 % reduction in annual spend for users who switch through the platform. --- ### Shape and volume risk: hidden costs in your energy forecast Source: https://tus.group/articles/shape-and-volume-risk-1 Category: procurement Published: 2026-08-17 Summary: Shape and volume risk can erode the savings you expect from a commercial energy contract. Inaccurate demand forecasts lead to over‑paying for unused capacity or paying penalties for shortfalls. Understanding how to model these risks and manage take‑or‑pay clauses is essential for finance directors and operations leaders. ## Thesis Accurate demand forecasting is the linchpin of any UK commercial energy contract, yet most organisations underestimate the financial impact of shape and volume risk. When the actual consumption pattern diverges from the forecast, suppliers apply penalties, adjust pricing, or enforce take‑or‑pay clauses that can add 5‑20% to the expected bill. By treating forecast error as a quantifiable risk and applying proven mitigation tools – such as TUS Group’s flex‑management platform – you can protect your bottom line and avoid hidden costs. ## What is shape and volume risk? ### Volume risk Volume risk is the uncertainty around the total amount of energy you will consume over a contract period. A contract may be priced on a fixed volume (e.g., 10 GWh per year) or on a flexible volume with a ceiling and floor. If you consume less than the contracted floor, you still pay for the minimum, while excess consumption above the ceiling may be charged at a higher spot rate. ### Shape risk Shape risk relates to the timing of that consumption – the hourly, daily, and seasonal profile. Suppliers often allocate generation or capacity based on the shape you provide. A mismatch can trigger capacity‑related charges, such as higher Transmission Network Use of System (TNUoS) or Distribution Use of System (DUoS) rates, and can affect eligibility for schemes like the Smart Export Guarantee (SEG). ## Why forecasting accuracy matters The UK energy market is increasingly price‑sensitive. Under the Streamlined Energy and Carbon Reporting (SECR) framework, organisations must disclose both energy use and associated carbon costs, meaning any variance from the forecast is visible to stakeholders. Moreover, Ofgem’s Maximum Household Supply (MHHS) rules and the Capacity Market impose penalties for non‑delivery that are calculated on a per‑MWh basis. A 5% forecasting error on a 150 GWh portfolio translates to a £7.5 million variance in cost, assuming an average price of £100 /MWh. ## Modelling shape and volume risk ### Data collection Start with high‑resolution metering data (15‑minute intervals) and align it with weather, production schedules, and operational changes. The Department for Energy Security and Net Zero (DESNZ) encourages the use of smart meters to improve data granularity. ### Statistical techniques * **Time‑series decomposition** – separates trend, seasonal, and residual components. * **Monte‑Carlo simulation** – runs thousands of demand scenarios to produce a probability distribution of volumes. * **Scenario analysis** – tests best‑case, base‑case, and worst‑case shapes against contract terms. ### Risk metrics * **Value at Risk (VaR)** – the maximum expected loss at a given confidence level (e.g., 95%). * **Conditional VaR (CVaR)** – average loss beyond the VaR threshold, useful for tail‑risk assessment. * **Shape‑risk coefficient** – ratio of peak‑to‑average demand deviation to the contracted peak capacity. ## Take‑or‑pay clauses: when they become a problem Take‑or‑pay clauses guarantee the supplier a minimum revenue, regardless of actual consumption. They are common in long‑term fixed‑price contracts and in capacity‑market agreements. The clause typically reads: *"The buyer shall purchase a minimum of X MWh each month, payable at the contracted rate, even if actual consumption is lower."* ### Cost implications If your forecast overshoots the actual demand, you incur a direct cost for the shortfall. For a 10 % over‑forecast on a 20 GWh annual contract at £95 /MWh, the take‑or‑pay penalty could be £190 k per year. Over a five‑year contract, that is £950 k – a material hit to EBITDA. ### When to renegotiate * **Significant operational change** – plant closures, new production lines, or major efficiency projects. * **Regulatory shifts** – changes to the Carbon Cost Levy (CCL) or the Renewable Obligation (RO) that alter the cost structure. * **Improved forecasting** – if you can demonstrate a reduction in forecast error (e.g., from 10% to 3%) using a robust model, you have leverage to soften the floor. ## Mitigating shape and volume risk with TUS Group TUS manages more than 150 GWh under flex‑management, allowing clients to adjust volume daily without penalty. In the last 12 months the TUS platform beat supplier projections by 20%, delivering measurable cost avoidance. Key mitigation tools include: * **Flex‑adjustment engine** – automatically aligns consumption with the contracted shape, reducing peak‑to‑average deviation by up to 15%. * **30+ supplier panel** – gives access to competitive offers, enabling a switch that on average saves 27% (via the free Yolk portal). * **Voltage optimisation** – delivers 5‑15% energy savings with a 2‑3 year payback, directly lowering the volume that needs to be purchased. By integrating these services, a typical mid‑size manufacturer can shave £200‑£400 k off an annual £5 m energy bill, while also reducing exposure to take‑or‑pay penalties. ## Practical steps for finance and operations leaders 1. **Audit current contracts** – identify any take‑or‑pay floors, caps, and shape‑related clauses. 2. **Implement high‑resolution metering** – ensure data feeds into a central analytics platform. 3. **Adopt a risk‑aware forecasting process** – use Monte‑Carlo simulation and publish VaR metrics to the board. 4. **Engage a flex‑management provider** – TUS’s 150 GWh flex portfolio demonstrates scalability. 5. **Review regulator‑driven incentives** – SECR, CCL, and the Capacity Market all influence the cost of over‑ or under‑consumption. 6. **Negotiate clause revisions** – use demonstrated forecasting improvements as leverage. ## Bottom line Shape and volume risk are not abstract concepts; they translate into concrete financial exposure that can erode the savings promised by any energy contract. By quantifying forecast error, modelling risk with robust statistical tools, and leveraging TUS Group’s flex‑management and optimisation services, you can turn hidden costs into managed, predictable spend. The result is a more resilient energy budget and a stronger position in contract negotiations. Frequently asked questions: Q: What is the difference between volume risk and shape risk? A: Volume risk concerns the total amount of energy you will use, while shape risk relates to when that energy is used. Both affect pricing, but shape risk also influences capacity‑related charges and eligibility for schemes like SEG. Q: How can take‑or‑pay clauses be mitigated? A: Mitigation options include improving forecast accuracy, negotiating flexible volume floors, and using a flex‑management service such as TUS, which can adjust consumption daily to stay within contract limits. Q: What tangible savings can TUS deliver? A: TUS has beaten supplier projections by 20% in the past year, manages over 150 GWh flexibly, and through its Yolk portal helps clients achieve an average 27% saving when switching suppliers. Voltage optimisation can add another 5‑15% reduction with a 2‑3 year payback. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-16 Category: procurement Published: 2026-08-14 Summary: Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price risk while retaining flexibility to benefit from market dips. This article explains the mechanics – period selection, tranches, caps, triggers and the timing of non‑commodity fixes – and walks through a realistic worked example using current UK pricing assumptions. The aim is to give finance directors and operations leaders a clear framework for negotiating contracts that align with SECR and Ofgem requirements. Multipurchase contracts are a strategic bridge between full‑on‑spot exposure and long‑term fixed‑price deals. For a UK business that consumes between 1 and 5 GWh a year, the core advantage is the ability to capture favourable market movements while protecting against price spikes that would breach SECR carbon‑reduction targets or inflate the Cost‑Cap Liability (CCL). The thesis is simple: a well‑structured multipurchase programme reduces volatility, improves cash‑flow predictability and can deliver up to 20 % better outcomes than a naïve supplier quote – a result TUS has demonstrated across 150 + GWh of flex‑managed portfolios. ## How multipurchase contracts are built ### Selecting the contract period The first decision is the settlement window – monthly, quarterly or seasonal. Monthly contracts provide the tightest alignment with consumption patterns but require more administrative effort. Quarterly periods are a common sweet spot for UK mid‑size firms; they balance granularity with operational simplicity. Seasonal contracts (e.g., winter vs summer) are useful when demand is highly weather‑driven, such as in manufacturing that runs heating loads in winter. The regulator does not prescribe a specific period, but Ofgem’s Minimum Household Supply Standard (MHSS) expects suppliers to manage exposure in a way that does not jeopardise system reliability, which a well‑chosen period can support. ### Tranches and volume allocation A multipurchase contract is typically split into tranches – discrete blocks of energy (e.g., 0‑500 MWh, 501‑1 000 MWh). Each tranche can carry its own price, cap, or trigger. This structure mirrors the way the Capacity Market allocates capacity‑related costs, allowing firms to hedge the bulk of their demand while leaving a smaller, high‑price tranche exposed to market movements. For a 3 GWh portfolio, a common split is: - Tranche 1: 0‑1 500 MWh (50 % of annual demand) – fixed price with a modest cap. - Tranche 2: 1 501‑2 500 MWh – price linked to a quarterly index with a trigger at £80/MWh. - Tranche 3: 2 501‑3 000 MWh – pure spot exposure, useful for capturing low‑price periods. ### Caps, floors and triggers Caps limit the maximum price payable for a tranche; floors set a minimum to protect the supplier’s margin. Triggers are conditional mechanisms that switch the pricing formula when a market indicator (e.g., the UK Power Exchange price) breaches a threshold. For example, a trigger at £75/MWh might shift the tranche from a fixed price to the wholesale index plus a 5 % margin. This approach aligns with the Ofgem‑mandated “price‑cap” principles that aim to prevent excessive supplier profiteering while ensuring supply security. ### Fixing non‑commodity components Non‑commodity elements – network charges (DUoS, TNUoS), Renewable Obligation Certificates (RO), and capacity payments – are often fixed at contract signing. Doing so removes a source of volatility that is outside the supplier’s control. The timing is critical: fixing these components early (typically at the contract’s inception) locks in the regulatory rates that are published annually by the Department for Energy Security and Net Zero (DESNZ). If a business expects regulatory changes – for instance, a likely increase in the Capacity Market price after the next auction – it may elect to keep a portion of the capacity charge variable, using a trigger that mirrors the auction outcome. ## Worked example – a 3 GWh annual portfolio Assumptions (based on Q3 2024 market data): - Wholesale electricity price (average) = £45 /MWh. - Capacity price = £20 /MWh. - Network charges (DUoS/TNUoS) = £10 /MWh (fixed at contract start). - RO credit = £2 /MWh (fixed). - Inflation‑linked escalation = 2 % per annum. - Desired cap for Tranche 1 = £80 /MWh. - Trigger for Tranche 2 = £75 /MWh, after which price = wholesale + 5 % margin. ### Step‑by‑step calculation 1. **Tranche 1 (0‑1 500 MWh)** – Fixed price of £70 /MWh (below the £80 cap). Total cost = 1 500 MWh × (£70 + £10 network + £2 RO) = £123 000. 2. **Tranche 2 (1 501‑2 500 MWh)** – Quarterly index price. Assume Q4 2024 spot = £78 /MWh, which triggers the 5 % margin (since >£75). Effective price = £78 × 1.05 = £81.9 /MWh. Total cost = 1 000 MWh × (£81.9 + £10 + £2) = £93 900. 3. **Tranche 3 (2 501‑3 000 MWh)** – Pure spot. Assume Q1 2025 spot = £42 /MWh. Total cost = 500 MWh × (£42 + £10 + £2) = £27 000. **Annual total cost** = £123 000 + £93 900 + £27 000 = £243 900. **Benchmark – 100 % fixed price at £85 /MWh** (including network and RO) would be 3 000 MWh × £85 = £255 000. **Result** – The multipurchase structure saves £11 100, or 4.4 % of total spend, while still capping exposure at £81.9 /MWh for the majority of the portfolio. If the spot price fell further, the business would capture additional upside in Tranche 3, improving the saving beyond the 4.4 % baseline. ### Sensitivity to trigger level If the trigger were set at £70 /MWh, the Q4 2024 price would have remained under the threshold, keeping the tranche at a pre‑agreed price of £68 /MWh. The cost for Tranche 2 would then be 1 000 MWh × (£68 + £10 + £2) = £80 000, delivering an extra £13 900 saving. This illustrates how trigger placement directly influences risk‑return balance. ## Aligning multipurchase contracts with UK policy - **SECR (Streamlined Energy and Carbon Reporting)** – By reducing price volatility, multipurchase contracts help firms meet the SECR requirement to demonstrate cost‑effective energy management. - **Ofgem’s price‑cap guidance** – Caps embedded in the contract must respect the regulator’s maximum allowable price, which for 2024‑25 is set at £79.73/MWh for standard domestic tariffs. For non‑domestic contracts, the principle of “reasonable pricing” still applies, and TUS’s track record of beating supplier projections by 20 % provides a defensible benchmark. - **Capacity Market and REGO** – Fixing the capacity component at contract signing aligns the firm’s cash‑flow with the annual auction outcomes, reducing exposure to the volatile capacity price that can swing between £15‑£30/MWh. - **TNUoS and DUoS** – These network charges are published annually by DESNZ; locking them in avoids surprise escalations that could otherwise erode the financial benefit of the multipurchase structure. ## Practical steps for finance and operations leaders 1. **Map annual demand** – Use smart‑meter data or the Yolk portal (which delivers an average 27 % switching saving) to confirm the 1‑5 GWh range. 2. **Define risk appetite** – Decide how much of the portfolio can be exposed to spot versus capped pricing. 3. **Select period and tranches** – Align period choice with internal budgeting cycles; design tranches that reflect operational peaks. 4. **Negotiate caps and triggers** – Leverage TUS’s 30 + supplier panel to benchmark caps; aim for a cap no higher than the historical 20 % premium over spot. 5. **Fix non‑commodity components early** – Capture the current network and RO rates; consider a separate clause for capacity price adjustments post‑auction. 6. **Monitor and adjust** – Use the free TUS portal to track actual spend versus contract assumptions; re‑balance tranches at each renewal. ## Bottom line Multipurchase contracts offer UK mid‑size businesses a pragmatic way to tame energy price risk without surrendering the upside of a falling market. By carefully selecting periods, structuring tranches, and embedding sensible caps and triggers, a 3 GWh portfolio can achieve a 4‑6 % cost reduction while remaining compliant with SECR, Ofgem and DESNZ requirements. The approach is underpinned by TUS’s proven ability to manage over 150 GWh of flex‑managed demand and to deliver savings that consistently beat supplier forecasts. Frequently asked questions: Q: What size of portfolio is ideal for a multipurchase contract? A: Multipurchase structures are most effective for portfolios between 1 GWh and 5 GWh per year, where the volume is sufficient to negotiate meaningful caps but still small enough to retain flexibility. Q: How often can the contract periods be changed? A: Period choices are set at contract inception, but many suppliers allow a renegotiation at each annual renewal, provided both parties agree to the new schedule. Q: Do caps apply to network charges as well as commodity price? A: Caps typically apply only to the commodity component. Network charges (DUoS/TNUoS) and regulatory levies are usually fixed at the prevailing DESNZ rates at the time of signing. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-15 Category: procurement Published: 2026-08-13 Summary: Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price risk while retaining flexibility to benefit from market dips. This article explains the mechanics – period selection, tranches, caps, triggers and the timing of non‑commodity fixes – and walks through a realistic worked example using current UK pricing assumptions. The aim is to give finance directors and operations leaders a clear framework for negotiating contracts that align with SECR and Ofgem requirements. Multipurchase contracts are a strategic bridge between full‑on‑spot exposure and long‑term fixed‑price deals. For a UK business that consumes between 1 and 5 GWh a year, the core advantage is the ability to capture favourable market movements while protecting against price spikes that would breach SECR carbon‑reduction targets or inflate the Cost‑Cap Liability (CCL). The thesis is simple: a well‑structured multipurchase programme reduces volatility, improves cash‑flow predictability and can deliver up to 20 % better outcomes than a naïve supplier quote – a result TUS has demonstrated across 150 + GWh of flex‑managed portfolios. ## How multipurchase contracts are built ### Selecting the contract period The first decision is the settlement window – monthly, quarterly or seasonal. Monthly contracts provide the tightest alignment with consumption patterns but require more administrative effort. Quarterly periods are a common sweet spot for UK mid‑size firms; they balance granularity with operational simplicity. Seasonal contracts (e.g., winter vs summer) are useful when demand is highly weather‑driven, such as in manufacturing that runs heating loads in winter. The regulator does not prescribe a specific period, but Ofgem’s Minimum Household Supply Standard (MHSS) expects suppliers to manage exposure in a way that does not jeopardise system reliability, which a well‑chosen period can support. ### Tranches and volume allocation A multipurchase contract is typically split into tranches – discrete blocks of energy (e.g., 0‑500 MWh, 501‑1 000 MWh). Each tranche can carry its own price, cap, or trigger. This structure mirrors the way the Capacity Market allocates capacity‑related costs, allowing firms to hedge the bulk of their demand while leaving a smaller, high‑price tranche exposed to market movements. For a 3 GWh portfolio, a common split is: - Tranche 1: 0‑1 500 MWh (50 % of annual demand) – fixed price with a modest cap. - Tranche 2: 1 501‑2 500 MWh – price linked to a quarterly index with a trigger at £80/MWh. - Tranche 3: 2 501‑3 000 MWh – pure spot exposure, useful for capturing low‑price periods. ### Caps, floors and triggers Caps limit the maximum price payable for a tranche; floors set a minimum to protect the supplier’s margin. Triggers are conditional mechanisms that switch the pricing formula when a market indicator (e.g., the UK Power Exchange price) breaches a threshold. For example, a trigger at £75/MWh might shift the tranche from a fixed price to the wholesale index plus a 5 % margin. This approach aligns with the Ofgem‑mandated “price‑cap” principles that aim to prevent excessive supplier profiteering while ensuring supply security. ### Fixing non‑commodity components Non‑commodity elements – network charges (DUoS, TNUoS), Renewable Obligation Certificates (RO), and capacity payments – are often fixed at contract signing. Doing so removes a source of volatility that is outside the supplier’s control. The timing is critical: fixing these components early (typically at the contract’s inception) locks in the regulatory rates that are published annually by the Department for Energy Security and Net Zero (DESNZ). If a business expects regulatory changes – for instance, a likely increase in the Capacity Market price after the next auction – it may elect to keep a portion of the capacity charge variable, using a trigger that mirrors the auction outcome. ## Worked example – a 3 GWh annual portfolio Assumptions (based on Q3 2024 market data): - Wholesale electricity price (average) = £45 /MWh. - Capacity price = £20 /MWh. - Network charges (DUoS/TNUoS) = £10 /MWh (fixed at contract start). - RO credit = £2 /MWh (fixed). - Inflation‑linked escalation = 2 % per annum. - Desired cap for Tranche 1 = £80 /MWh. - Trigger for Tranche 2 = £75 /MWh, after which price = wholesale + 5 % margin. ### Step‑by‑step calculation 1. **Tranche 1 (0‑1 500 MWh)** – Fixed price of £70 /MWh (below the £80 cap). Total cost = 1 500 MWh × (£70 + £10 network + £2 RO) = £123 000. 2. **Tranche 2 (1 501‑2 500 MWh)** – Quarterly index price. Assume Q4 2024 spot = £78 /MWh, which triggers the 5 % margin (since >£75). Effective price = £78 × 1.05 = £81.9 /MWh. Total cost = 1 000 MWh × (£81.9 + £10 + £2) = £93 900. 3. **Tranche 3 (2 501‑3 000 MWh)** – Pure spot. Assume Q1 2025 spot = £42 /MWh. Total cost = 500 MWh × (£42 + £10 + £2) = £27 000. **Annual total cost** = £123 000 + £93 900 + £27 000 = £243 900. **Benchmark – 100 % fixed price at £85 /MWh** (including network and RO) would be 3 000 MWh × £85 = £255 000. **Result** – The multipurchase structure saves £11 100, or 4.4 % of total spend, while still capping exposure at £81.9 /MWh for the majority of the portfolio. If the spot price fell further, the business would capture additional upside in Tranche 3, improving the saving beyond the 4.4 % baseline. ### Sensitivity to trigger level If the trigger were set at £70 /MWh, the Q4 2024 price would have remained under the threshold, keeping the tranche at a pre‑agreed price of £68 /MWh. The cost for Tranche 2 would then be 1 000 MWh × (£68 + £10 + £2) = £80 000, delivering an extra £13 900 saving. This illustrates how trigger placement directly influences risk‑return balance. ## Aligning multipurchase contracts with UK policy - **SECR (Streamlined Energy and Carbon Reporting)** – By reducing price volatility, multipurchase contracts help firms meet the SECR requirement to demonstrate cost‑effective energy management. - **Ofgem’s price‑cap guidance** – Caps embedded in the contract must respect the regulator’s maximum allowable price, which for 2024‑25 is set at £79.73/MWh for standard domestic tariffs. For non‑domestic contracts, the principle of “reasonable pricing” still applies, and TUS’s track record of beating supplier projections by 20 % provides a defensible benchmark. - **Capacity Market and REGO** – Fixing the capacity component at contract signing aligns the firm’s cash‑flow with the annual auction outcomes, reducing exposure to the volatile capacity price that can swing between £15‑£30/MWh. - **TNUoS and DUoS** – These network charges are published annually by DESNZ; locking them in avoids surprise escalations that could otherwise erode the financial benefit of the multipurchase structure. ## Practical steps for finance and operations leaders 1. **Map annual demand** – Use smart‑meter data or the Yolk portal (which delivers an average 27 % switching saving) to confirm the 1‑5 GWh range. 2. **Define risk appetite** – Decide how much of the portfolio can be exposed to spot versus capped pricing. 3. **Select period and tranches** – Align period choice with internal budgeting cycles; design tranches that reflect operational peaks. 4. **Negotiate caps and triggers** – Leverage TUS’s 30 + supplier panel to benchmark caps; aim for a cap no higher than the historical 20 % premium over spot. 5. **Fix non‑commodity components early** – Capture the current network and RO rates; consider a separate clause for capacity price adjustments post‑auction. 6. **Monitor and adjust** – Use the free TUS portal to track actual spend versus contract assumptions; re‑balance tranches at each renewal. ## Bottom line Multipurchase contracts offer UK mid‑size businesses a pragmatic way to tame energy price risk without surrendering the upside of a falling market. By carefully selecting periods, structuring tranches, and embedding sensible caps and triggers, a 3 GWh portfolio can achieve a 4‑6 % cost reduction while remaining compliant with SECR, Ofgem and DESNZ requirements. The approach is underpinned by TUS’s proven ability to manage over 150 GWh of flex‑managed demand and to deliver savings that consistently beat supplier forecasts. Frequently asked questions: Q: What size of portfolio is ideal for a multipurchase contract? A: Multipurchase structures are most effective for portfolios between 1 GWh and 5 GWh per year, where the volume is sufficient to negotiate meaningful caps but still small enough to retain flexibility. Q: How often can the contract periods be changed? A: Period choices are set at contract inception, but many suppliers allow a renegotiation at each annual renewal, provided both parties agree to the new schedule. Q: Do caps apply to network charges as well as commodity price? A: Caps typically apply only to the commodity component. Network charges (DUoS/TNUoS) and regulatory levies are usually fixed at the prevailing DESNZ rates at the time of signing. --- ### Why fixing non‑commodity costs is a forgotten lever for UK businesses Source: https://tus.group/articles/why-fix-non-commodity-costs-1 Category: procurement Published: 2026-08-12 Summary: Finance directors and operations leaders often focus on commodity price volatility, overlooking the non‑commodity charges that can erode savings year on year. Understanding which components – such as TNUoS, DUoS, RO and others – actually fluctuate, and where fixing them adds value, is essential for a robust procurement strategy. ## The hidden cost of non‑commodity charges In most energy procurement discussions the headline is the kWh price, but the real bill is built on a raft of non‑commodity charges that sit on top of the commodity rate. For a UK business on a flex or multi‑purchase agreement, those charges can account for 30‑45% of the total invoice. The thesis is simple: if you ignore the volatility in non‑commodity components you leave money on the table, and you expose the organisation to unexpected cost spikes that undermine any commodity‑price win. ## Which non‑commodity components really move year‑on‑year ### Transmission Network Use of System (TNUoS) TNUoS is a capacity‑based charge set by the regulator (Ofgem) and reflects the cost of using the high‑voltage transmission network. It is reviewed annually in the RIIO‑T2 price control and can change by up to 10% year‑on‑year depending on network investment needs. ### Distribution Use of System (DUoS) and Balancing Services Use of System (BSUoS) DUoS charges are set by the Distribution Network Operators (DNOs) and are indexed to the Retail Price Index (RPI) with a capped uplift of 5% per annum. BSUoS, introduced under the Capacity Market, is a separate balancing charge that can vary with system stress and has shown swings of 3‑8% in the last three years. ### Reactive Power (RO) and System Services The Reactive Power (RO) charge reflects the cost of providing voltage support and is linked to the amount of reactive power a customer draws. It is a usage‑based charge and can rise sharply during periods of high network utilisation, typically 5‑12% year‑on‑year. ### Feed‑in Tariff (FiT) and Contracts for Difference (CfD) Both FiT and CfD are policy‑driven mechanisms that affect the net price of renewable generation. While the headline rates are fixed for the contract term, the settlement price can fluctuate with the market reference price, leading to an effective cost variation of up to 15% for businesses that have on‑site generation or are purchasing renewable‑certified electricity. ### Climate Change Levy (CCL) CCL is a flat rate tax on non‑domestic electricity consumption. It is reviewed annually and can be adjusted by the Treasury. Recent adjustments have ranged between 2% and 6%. ### Energy Efficiency Obligation (E11) and Other Regulatory Charges The E11 levy, part of the Energy Savings Opportunity Scheme, is applied to large energy users and can vary with the overall scheme funding level. Historically it has moved between 1% and 4% of the total bill. ## Fixing versus passing through – where the lever is strongest ### Fixed‑price contracts for network charges A growing number of suppliers now offer contracts that lock in TNUoS, DUoS and BSUoS for the duration of the agreement. By fixing these charges, a business can smooth cash‑flow and protect against the RPI‑linked uplift that would otherwise hit the balance sheet each year. ### Volume‑based hedging for reactive power Because RO is usage‑driven, the most effective mitigation is to reduce reactive power demand through power factor correction equipment. Where that is not feasible, a volume‑based hedge – agreeing a capped RO rate for a defined kVArh band – can provide certainty. ### Renewable‑generation settlement hedges For firms with on‑site solar or wind, fixing the settlement price of FiT or CfD via a renewable‑energy‑price‑hedge (REPH) removes the exposure to market reference price swings. TUS’s flex‑management platform has already overseen more than 150 GWh of such arrangements, beating supplier projections by 20% in the last 12 months. ### CCL and E11 pass‑through considerations CCL is a statutory tax and cannot be fixed, but it can be budgeted for with a simple inflation‑adjusted forecast. E11, however, can be negotiated as part of a broader procurement package – some suppliers bundle a fixed E11 contribution into the overall price, effectively turning a variable levy into a predictable cost. ## The role of flex management and supplier panels TUS operates a 30‑plus supplier panel that gives clients access to competitive fixed‑price offers across the full suite of non‑commodity charges. By aggregating demand, the panel can negotiate caps on TNUoS and DUoS that are typically 5‑10% lower than the standard market rates. The platform’s free portal, Yolk, also provides real‑time visibility of each charge component, enabling finance teams to spot anomalies early and trigger renegotiations before the annual price review. ## Practical steps for finance directors and operations leaders 1. **Map your current bill** – Use Yolk to break down the invoice into commodity and each non‑commodity component. 2. **Identify volatility drivers** – Look at the historical change percentages for TNUoS, DUoS, RO, FiT, CfD, BSUoS, CCL and E11 over the past three years. 3. **Set a fixing strategy** – Prioritise fixing TNUoS, DUoS and BSUoS where the uplift potential exceeds 4% per annum. Consider volume‑based hedges for RO and settlement hedges for renewable mechanisms. 4. **Leverage the supplier panel** – Invite at least three panel suppliers to submit fixed‑price proposals that include the targeted non‑commodity charges. 5. **Monitor and adjust** – Review the Yolk dashboard quarterly; if any charge deviates from the agreed cap by more than 2%, engage the supplier to remediate. ## Bottom line Non‑commodity charges are a predictable, yet often overlooked, source of cost drift for UK businesses on flex or multi‑purchase agreements. By fixing the most volatile components – TNUoS, DUoS, BSUoS and, where feasible, RO and renewable settlement prices – you protect cash‑flow and ensure that commodity‑price wins translate into real bottom‑line savings. Leveraging TUS’s flex‑management expertise and its extensive supplier panel makes the fixing process both transparent and cost‑effective. Frequently asked questions: Q: Which non‑commodity charges tend to increase the most each year? A: TNUoS and DUoS are the biggest movers, with annual changes of up to 10% and 5% respectively, driven by network investment and RPI indexing. Q: Can I fix the Climate Change Levy? A: CCL is a statutory tax and cannot be fixed, but you can budget for it using an inflation‑adjusted forecast. Q: How does TUS help me lock in non‑commodity costs? A: Through its 30‑plus supplier panel and the Yolk portal, TUS negotiates fixed‑price contracts for TNUoS, DUoS, BSUoS and offers volume‑based hedges for reactive power, delivering savings that have outperformed supplier forecasts by 20% in the last 12 months. --- ### A practical deep dive into multipurchase contracts Source: https://tus.group/articles/multipurchase-deep-dive-14 Category: procurement Published: 2026-08-11 Summary: Multipurchase contracts let UK firms with 1‑5 GWh of demand lock in volume and price while retaining flexibility. This guide explains period choices, tranche structures, caps, triggers and the timing for fixing non‑commodity elements, and walks through a realistic worked example. ## Thesis Multipurchase contracts are a middle ground between spot buying and full‑scale power purchase agreements. For businesses that consume between 1 and 5 GWh a year, they provide price certainty for a defined volume while preserving the ability to react to market swings. The key to value is understanding how periods, tranches, caps and triggers interact, and when to lock in non‑commodity components such as capacity, transmission and ancillary services. ## How multipurchase contracts are structured ### Period choices – monthly, quarterly, seasonal The contract period determines how often the volume commitment is reconciled against actual consumption. * **Monthly** contracts suit organisations with a tight operational calendar – for example a data centre that can forecast its load to a few percent each month. They allow rapid adjustment but often carry a higher premium because the supplier bears more price risk. * **Quarterly** contracts are the most common for 1‑5 GWh portfolios. They balance administrative burden with market exposure and align with the typical reporting cadence of the SECR (Streamlined Energy and Carbon Reporting) and Ofgem’s Market-wide Half‑Hourly Settlement (MHHS) data. * **Seasonal** contracts (e.g., winter vs summer) are useful where demand is highly weather‑dependent, such as a manufacturing site with heating loads. Seasonal contracts lock in a larger volume for a defined season, reducing exposure to winter price spikes. ### Tranches – layering volume and price A multipurchase deal is usually broken into tranches, each with its own price and volume ceiling. For a 3 GWh annual portfolio you might see: 1. **Base tranche** – 1.2 GWh at a fixed price, representing the firm‑core load. 2. **Flex tranche** – up to 0.9 GWh that can be called on‑demand, priced at a spread over the market index (e.g., £2/MWh above the ICE UK Power Index). 3. **Optional tranche** – up to 0.9 GWh that can be purchased if market prices exceed a trigger (e.g., £120/MWh). This tranche is often called a "cap‑and‑trigger" component. The advantage of tranches is that you can match the contract to the shape of your demand curve, and you only pay the higher spread for the volume you actually need. ### Caps and triggers – managing price risk * **Cap** – the maximum price you will pay for the flex or optional tranche. If the market price exceeds the cap, the supplier absorbs the excess. * **Trigger** – the market price at which the optional tranche becomes available. Below the trigger you simply use the base or flex tranche; above it you can call the optional tranche to avoid paying spot prices. A typical configuration for a 2 GWh portfolio might be: * Flex tranche cap: £95/MWh (spot price today ~£70/MWh). * Optional tranche trigger: £115/MWh, with a cap of £130/MWh. These levels are set after analysing historic price volatility (e.g., the last five years of Ofgem’s market data) and the organisation’s risk appetite. ## When to fix non‑commodity components Non‑commodity elements include: * **Capacity charges** – NESO’s Capacity Market payments. * **Transmission and distribution tariffs** – TNUoS, DUoS, REGO. * **Ancillary services** – Frequency response, reserve. Fixing these early can lock in a 5‑15 % saving on total energy cost, with a typical payback of 2‑3 years when combined with voltage optimisation. TUS’s own portfolio optimisation has delivered a 20 % improvement over supplier forecasts in the last 12 months, underlining the benefit of early lock‑in. ### Timing guidelines 1. **Capacity** – Secure at least 12 months before the contract start date to capture the next Capacity Market auction window. 2. **Transmission & distribution** – Negotiate with the 30+‑supplier panel early; many suppliers can offer bundled TNUoS/DUoS discounts when the volume is committed. 3. **Ancillary services** – Align with the flex tranche; if you plan to use the optional tranche, ensure the supplier can provide the required reserve capacity. ## Worked example – a 3 GWh annual portfolio ### Assumptions * Annual consumption: 3 GWh (average 250 MWh/month). * Market reference price: £70/MWh (ICE UK Power Index average 2023‑24). * Desired price certainty for 60 % of volume (1.8 GWh). * Risk appetite: willing to pay a £5/MWh spread for the remaining 40 % (1.2 GWh). * Caps and triggers set based on historic price peaks (max £130/MWh in 2022). ### Contract layout | Tranche | Volume (MWh) | Price basis | Spread / Cap | Trigger | |---|---|---|---|---| | Base | 1 200 | Fixed £75/MWh | – | – | | Flex | 600 | ICE + £5/MWh | Cap £95/MWh | – | | Optional | 600 | ICE + £10/MWh | Cap £130/MWh | Trigger £115/MWh | ### Cost calculation (worst‑case scenario) 1. **Base tranche**: 1 200 MWh × £75 = £90,000. 2. **Flex tranche** – assume market spikes to £110/MWh for half the month (300 MWh). Supplier charges cap £95/MWh. * 300 MWh × £95 = £28,500. * Remaining 300 MWh at market (£70 + £5) = 300 MWh × £75 = £22,500. * Flex total = £51,000. 3. **Optional tranche** – market exceeds trigger for 200 MWh (price £120/MWh). Supplier applies cap £130/MWh. * 200 MWh × £130 = £26,000. * Remaining 400 MWh at market (£70 + £10) = 400 MWh × £80 = £32,000. * Optional total = £58,000. **Total annual cost** = £90,000 + £51,000 + £58,000 = **£199,000**. ### Comparison with pure spot buying Spot cost (average £70/MWh) for 3 GWh = 3 000 MWh × £70 = £210,000. **Saving** = £11,000 or **5.2 %**, plus the operational certainty of knowing the cost of 80 % of volume in advance. When combined with TUS’s voltage optimisation (average 10 % reduction) the net saving can rise to 12‑15 % over a 3‑year horizon. ## Regulatory context * **SECR** – requires large UK organisations to report energy use and associated carbon; a multipurchase contract provides a clear audit trail. * **Ofgem’s MHHS** – monthly settlement aligns with quarterly contract periods, simplifying reconciliation. * **DESNZ** – the Department for Energy Security and Net Zero publishes guidance on demand‑side response, which can be layered onto the flex tranche. * **Capacity Market** – securing capacity early avoids exposure to the annual auction volatility. ## Practical steps for finance and operations leaders 1. **Map demand** – use your existing energy management system to segment firm, flexible and discretionary loads. 2. **Define risk appetite** – decide what proportion of volume you need at a fixed price versus what you can leave exposed. 3. **Select period** – match contract period to your internal reporting cadence. 4. **Model caps and triggers** – run Monte‑Carlo simulations using historic ICE data to set realistic levels. 5. **Engage a supplier panel** – TUS’s 30+‑supplier panel can provide competitive spreads and bundled non‑commodity services. 6. **Negotiate non‑commodity lock‑ins** – aim to secure capacity, TNUoS and ancillary services at least 12 months ahead. 7. **Implement monitoring** – integrate the contract’s tranching logic into your ERP or energy dashboard to trigger optional purchases automatically. ## Bottom line Multipurchase contracts give UK mid‑size energy users a pragmatic blend of price certainty and flexibility. By selecting the right period, structuring tranches, and fixing non‑commodity components early, you can achieve 5‑10 % cost savings on a pure spot baseline, with additional upside from voltage optimisation and demand‑side response. The approach is transparent, aligns with SECR and Ofgem reporting, and can be executed through TUS’s extensive supplier panel, which has already delivered a 20 % performance uplift across 150 GWh of flex‑managed volume. Frequently asked questions: Q: What size of portfolio is ideal for a multipurchase contract? A: Businesses with 1‑5 GWh of annual consumption benefit most, as the contract size is large enough to negotiate meaningful spreads but small enough to retain operational flexibility. Q: How do caps and triggers differ from a traditional fixed‑price PPA? A: A PPA locks the price for the entire volume. Caps limit the maximum price you pay on a flex or optional tranche, while triggers determine when the optional tranche becomes available, allowing you to benefit from lower market prices when they occur. Q: Can I combine a multipurchase contract with on‑site generation? A: Yes. On‑site generation can be treated as a negative load in the volume calculations, reducing the amount you need to purchase and improving the economics of the base and flex tranches. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-13 Category: procurement Published: 2026-08-10 Summary: Multipurchase contracts let organisations with 1‑5 GWh of annual demand secure price certainty while still capturing market upside. This article explains period choices, tranches, caps, triggers and the timing of non‑commodity fixes, and includes a worked example based on current UK pricing. It also shows how TUS Group’s services can enhance the value of a multipurchase strategy. ## Thesis Multipurchase contracts provide a middle ground between a full‑on fixed price deal and a spot‑market exposure. For businesses consuming 1‑5 GWh a year they deliver predictable cash‑flows, protect against price spikes, and still allow upside capture when wholesale prices fall. The key is to structure the contract with the right periods, tranches, caps and triggers, and to decide when to lock in non‑commodity components such as network charges and renewable obligations. ## How multipurchase contracts work ### Core structure A multipurchase contract is a series of linked purchase agreements that together cover a defined volume of electricity. Each link – or tranche – is priced against a reference market (e.g., the N2EX or ICE futures) and may have its own duration (monthly, quarterly, or seasonal). The buyer commits to buying a set amount in each tranche, but the price can be adjusted by predefined caps or triggers. ### Period choices | Period | Typical use‑case | Advantages | |--------|-----------------|------------| | Monthly | Short‑term cash‑flow planning, high volatility periods | Quick reaction to price swings, easy budgeting | | Quarterly | Aligns with many corporate reporting cycles, smoother price curve | Reduced administrative overhead, balanced risk | | Seasonal (e.g., winter/summer) | Aligns with demand patterns, especially for heating‑heavy sites | Simpler contract management, leverages predictable seasonal spreads | Choosing the right period depends on the firm’s internal budgeting cadence and its appetite for price risk. For a 3 GWh portfolio, a mixed approach – monthly tranches for the winter peak and quarterly for the rest of the year – often yields the best balance. ## Managing caps and triggers Caps limit the maximum price payable for a tranche, while triggers can switch the contract to a different pricing formula if market conditions breach a threshold. For example, a cap of £70 /MWh on a winter monthly tranche protects against extreme spikes, but a trigger at £55 /MWh could shift the pricing to a reference index plus a modest margin, allowing the buyer to benefit from lower wholesale rates. Regulatory context matters. Under the **SECR** (Streamlined Energy and Carbon Reporting) framework, firms must report energy costs, so caps help keep those figures within forecasted budgets. Additionally, the **Capacity Market** price signals can be incorporated as a trigger, ensuring the contract reflects system‑wide scarcity pricing when it rises above £30 /MWh. ## Fixing non‑commodity components Non‑commodity components include Transmission Network Use of System (TNUoS) charges, Distribution Use of System (DUoS) tariffs, Climate Change Levy (CCL), and Renewable Obligation Certificates (RO). These elements are largely regulatory and change infrequently, but timing their fixation can affect overall contract economics. * **When to fix:** If the regulatory horizon is within the next 12‑18 months, locking in DUoS and TNUoS rates can avoid future escalations. The **DESNZ** publishes annual updates to network tariffs; fixing them after the update reduces the risk of surprise cost increases. * **When to keep flexible:** For longer‑term contracts (beyond 3 years), it may be prudent to keep CCL and RO exposure flexible, as policy shifts (e.g., adjustments to the **Carbon Price Support**) can materially affect those costs. ## Worked example – realistic UK pricing assumptions **Assumptions** - Annual demand: 3 GWh (≈ 8,219 MWh per month average) - Contract horizon: 24 months - Period split: 12 monthly winter tranches (Nov–Mar) and 12 quarterly non‑winter tranches - Reference market: ICE European Power Futures (average £55 /MWh for winter, £45 /MWh for non‑winter) - Caps: £70 /MWh for winter, £60 /MWh for non‑winter - Triggers: Switch to reference + £5 /MWh if spot falls below £48 /MWh (winter) or £38 /MWh (non‑winter) - Fixed non‑commodity components: TNUoS £12 /MWh, DUoS £6 /MWh, CCL £0.5 /MWh (flexible), RO £0.3 /MWh (flexible) **Step‑by‑step calculation** 1. **Allocate volume** – 60 % of annual demand (1,831 MWh) is assigned to winter monthly tranches, the remaining 40 % (1,388 MWh) to quarterly non‑winter tranches. 2. **Apply caps** – If the ICE winter price spikes to £80 /MWh, the cap limits the payable price to £70 /MWh for that month. 3. **Apply triggers** – In a month where the spot price falls to £45 /MWh, the trigger activates and the price becomes £45 + £5 = £50 /MWh, delivering upside compared with a fixed‑price deal at £60 /MWh. 4. **Add non‑commodity components** – For each MWh, add the fixed TNUoS and DUoS rates (£18 /MWh total). The flexible CCL and RO are added at the prevailing rates at settlement. 5. **Calculate total cost** – Assuming an average realised price of £55 /MWh after caps and triggers, the total cost per MWh is: - Commodity: £55 /MWh - TNUoS + DUoS: £18 /MWh - CCL + RO (average): £0.8 /MWh - **Total:** £73.8 /MWh 6. **Compare with a pure fixed‑price contract** – A 24‑month fixed price of £78 /MWh would have cost £78 × 3 GWh = £234 m, whereas the multipurchase structure yields an expected cost of £73.8 × 3 GWh = £221.4 m – a saving of roughly **5 %**. **Key take‑aways** - Caps protect against extreme spikes (e.g., winter 2022‑23 price spikes above £100 /MWh). - Triggers let the buyer capture market declines, delivering upside. - Fixing network charges after the annual DESNZ update locks in predictable costs. - The flexibility built into the contract aligns with SECR reporting requirements and reduces variance in the annual energy spend. ## Integration with TUS Group services TUS Group’s portfolio of tools and expertise can enhance a multipurchase strategy: - **Flex management:** With over **150 GWh** under active flex management, TUS can provide real‑time demand response to smooth consumption during high‑price periods, further reducing exposure. - **Supplier panel:** Access to a **30‑plus supplier panel** ensures competitive pricing and the ability to negotiate caps that beat supplier projections by **20 %** on average. - **Yolk portal:** The free **Yolk** portal gives finance directors instant visibility of contract performance, enabling quick trigger decisions and supporting SECR reporting. - **Voltage optimisation:** For sites where voltage optimisation is feasible, TUS delivers **5‑15 %** savings with a typical **2‑3 year payback**, complementing the cost reductions from the multipurchase contract. - **Switching savings:** Historical data shows a **27 %** average saving when businesses switch through TUS, reinforcing the value of a well‑structured multipurchase approach. ## Bottom line Multipurchase contracts are a pragmatic tool for UK businesses with 1‑5 GWh of annual demand. By selecting appropriate periods, layering caps and triggers, and timing the fixation of non‑commodity components, organisations can achieve price certainty while preserving upside potential. Coupled with TUS Group’s flex‑management expertise, supplier network, and analytical portals, the approach can deliver measurable cost reductions and compliance benefits. ## FAQs - **What is the main advantage of a monthly tranche versus a quarterly one?** Monthly tranches give tighter alignment with short‑term price volatility, allowing caps and triggers to respond quickly to market spikes. Quarterly tranches reduce administrative overhead and smooth price curves, which is useful for stable budgeting periods. - **How often should non‑commodity components be reviewed?** Network charges (TNUoS, DUoS) should be reviewed after each DESNZ tariff update, typically annually. Regulatory components like CCL and RO are best kept flexible unless a policy change is announced. - **Can a multipurchase contract be combined with on‑site generation?** Yes. On‑site generation can be treated as a negative tranche, reducing the volume that needs to be purchased and improving the overall economics of the contract. Frequently asked questions: Q: What is the main advantage of a monthly tranche versus a quarterly one? A: Monthly tranches give tighter alignment with short‑term price volatility, allowing caps and triggers to respond quickly to market spikes. Quarterly tranches reduce administrative overhead and smooth price curves, which is useful for stable budgeting periods. Q: How often should non‑commodity components be reviewed? A: Network charges (TNUoS, DUoS) should be reviewed after each DESNZ tariff update, typically annually. Regulatory components like CCL and RO are best kept flexible unless a policy change is announced. Q: Can a multipurchase contract be combined with on‑site generation? A: Yes. On‑site generation can be treated as a negative tranche, reducing the volume that needs to be purchased and improving the overall economics of the contract. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-12 Category: procurement Published: 2026-08-07 Summary: Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price bands while retaining flexibility to adjust volumes as business needs change. This article explains period choices, tranche structures, caps, triggers and the optimal moment to fix non‑commodity components, finishing with a realistic worked example based on current UK market prices. ## The thesis For UK businesses that consume between 1 and 5 GWh a year, a well‑designed multipurchase contract can deliver the price certainty of a fixed‑price deal without sacrificing the ability to respond to seasonal demand swings or operational changes. By layering volume tranches, caps and trigger mechanisms, the contract becomes a strategic tool rather than a static purchase. ## Why multipurchase matters The UK’s SECR (Streamlined Energy and Carbon Reporting) regime forces large non‑SMEs to report energy use and carbon intensity, while the Ofgem‑mandated Minimum Household Energy Standards (MHHS) push suppliers to offer more transparent pricing. In this environment, finance directors need a procurement approach that: * Reduces exposure to volatile spot prices, which have swung more than 30 % in the last 12 months. * Aligns energy spend with cash‑flow planning, especially when capital is tied up in other decarbonisation projects. * Provides a clear audit trail for ESG reporting and future CCL (Carbon Contracts for Difference) eligibility. TUS currently manages over 150 GWh under flex‑management programmes, proving that sophisticated volume‑based contracts can be administered at scale while delivering savings that beat supplier forecasts by around 20 %. ## Contract mechanics ### Period choices – monthly, quarterly, seasonal The contract period defines the granularity at which volume commitments are measured. * **Monthly** – best for businesses with tight production schedules (e.g., food processing) where demand can be forecasted to within ±5 %. * **Quarterly** – suits most office‑based or mixed‑use portfolios, balancing forecasting effort with price certainty. * **Seasonal** – aligns with natural demand cycles (winter heating, summer cooling) and is often paired with a “baseline” tranche that covers the bulk of annual consumption. Choosing the right period is a trade‑off between forecasting accuracy and administrative overhead. A mis‑aligned period can trigger unnecessary penalties or force the business to purchase excess volume at spot rates. ### Tranches, caps and triggers A multipurchase contract typically comprises several **tranches** – each a volume band with its own price. * **Base tranche** – covers the expected core demand (e.g., 60 % of annual forecast). Price is usually the lowest tier because the supplier has certainty of volume. * **Flex tranche** – captures the remaining 40 % and is priced higher, reflecting the risk the supplier bears. * **Cap** – a maximum price the buyer will pay for any volume exceeding the flex tranche. Caps protect against extreme market spikes. * **Trigger** – a predefined market event (e.g., spot price > £120/MWh for three consecutive days) that automatically moves excess volume into the capped tier. By structuring caps and triggers, the buyer can limit exposure while giving the supplier an incentive to manage supply risk. ### When to fix non‑commodity components Non‑commodity components include network charges (DUoS, TNUoS), renewable obligation certificates (RO), and any ancillary services. Fixing these early can lock in a predictable total cost of ownership, but it also removes the ability to benefit from future regulatory changes (e.g., a reduction in REGO rates). The optimal timing is: 1. **Before the contract start date** – if the business has a stable load profile and wants a single‑line invoice. 2. **After the first 12 months** – once actual consumption data validates the forecast, allowing a renegotiation of network charge allocations. ## Worked example – 3 GWh annual portfolio Assume a manufacturing firm with the following profile: * Annual demand: 3 GWh (≈8,220 MWh per month on average). * Seasonal split: 40 % winter (Nov‑Mar), 30 % summer (Jun‑Aug), 30 % shoulder. * Market reference price: £55/MWh (spot average 2024 Q2). * Desired price certainty: 20 % below spot for base volume. ### Step 1 – Define periods and tranches * **Period**: Quarterly, to match production planning. * **Base tranche**: 60 % of forecast = 4,932 MWh per year (≈1,233 MWh per quarter). * **Flex tranche**: remaining 40 % = 3,288 MWh per year (≈822 MWh per quarter). ### Step 2 – Set price tiers * **Base price**: £44/MWh (20 % discount to spot). * **Flex price**: £58/MWh (≈5 % premium to spot, reflecting risk). * **Cap price**: £85/MWh (protects against extreme spikes). ### Step 3 – Define trigger If the quarterly average spot price exceeds £120/MWh for two consecutive weeks, any volume above the flex tranche moves to the cap tier. ### Step 4 – Calculate annual cost under three scenarios | Scenario | Spot average | Volume in base | Volume in flex | Volume in cap | Total cost | |---|---|---|---|---|---| | **A – Stable market** | £55/MWh | 4,932 MWh @ £44 = £217,008 | 3,288 MWh @ £58 = £190,704 | 0 | **£407,712** | | **B – Moderate spike** (quarterly spot £115/MWh) | £115/MWh | 4,932 MWh @ £44 = £217,008 | 2,500 MWh @ £58 = £145,000 | 788 MWh @ £85 = £66,980 | **£428,988** | | **C – Extreme spike** (quarterly spot £130/MWh, trigger hit) | £130/MWh | 4,932 MWh @ £44 = £217,008 | 2,000 MWh @ £58 = £116,000 | 1,288 MWh @ £85 = £109,480 | **£442,488** | Even in the worst‑case scenario the contract caps total spend at roughly £442k, compared with an unhedged spot cost of 3 GWh × £130/MWh = £390k – a modest premium for certainty, but the firm avoids the risk of a further price surge. ## Risk and optimisation * **Forecast accuracy** – The base tranche should be set using a rolling 12‑month average, updated quarterly. TUS’s flex‑management platform can automate this, reducing the chance of over‑commitment. * **Supplier selection** – With a 30‑plus supplier panel, the buyer can benchmark base‑price discounts. In the last 12 months TUS‑managed contracts beat supplier projections by 20 % on average. * **Regulatory impact** – Upcoming changes to the Capacity Market and potential adjustments to the CCL could affect the value of the cap tier. Embedding a review clause at the 12‑month mark allows the contract to be re‑priced in line with new policy. * **Technology integration** – Linking the contract to a real‑time energy management system (EMS) enables automatic re‑allocation of excess flex volume to on‑site generation or storage, further reducing exposure. ## Bottom line Multipurchase contracts give UK businesses with 1‑5 GWh of demand a pragmatic blend of price certainty and operational flexibility. By selecting the appropriate period, structuring tranches with sensible caps and triggers, and timing the fixation of non‑commodity components, finance directors can lock in savings that sit comfortably within SECR reporting requirements while preserving the ability to adapt to market or regulatory shifts. A disciplined forecasting process, supported by TUS’s portfolio‑wide data, turns the contract from a simple purchase into a strategic asset. Frequently asked questions: Q: What size of portfolio is best suited to a multipurchase contract? A: Businesses with an annual demand of 1‑5 GWh benefit most, as the volume is large enough to negotiate tiered pricing but small enough to retain flexibility without a full‑scale PPA. Q: How often should the volume forecast be updated? A: Quarterly updates are standard; using a rolling 12‑month average reduces the risk of over‑ or under‑committing to the base tranche. Q: Can network charges be fixed within a multipurchase contract? A: Yes, they can be fixed at contract start for invoicing simplicity, but many firms renegotiate after the first year to capture any changes in DUoS/TNUoS rates. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-11 Category: procurement Published: 2026-08-06 Summary: Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price bands while retaining flexibility to adjust volumes as business needs change. This article explains period choices, tranche structures, caps, triggers and the optimal moment to fix non‑commodity components, finishing with a realistic worked example based on current UK market prices. ## The thesis For UK businesses that consume between 1 and 5 GWh a year, a well‑designed multipurchase contract can deliver the price certainty of a fixed‑price deal without sacrificing the ability to respond to seasonal demand swings or operational changes. By layering volume tranches, caps and trigger mechanisms, the contract becomes a strategic tool rather than a static purchase. ## Why multipurchase matters The UK’s SECR (Streamlined Energy and Carbon Reporting) regime forces large non‑SMEs to report energy use and carbon intensity, while the Ofgem‑mandated Minimum Household Energy Standards (MHHS) push suppliers to offer more transparent pricing. In this environment, finance directors need a procurement approach that: * Reduces exposure to volatile spot prices, which have swung more than 30 % in the last 12 months. * Aligns energy spend with cash‑flow planning, especially when capital is tied up in other decarbonisation projects. * Provides a clear audit trail for ESG reporting and future CCL (Carbon Contracts for Difference) eligibility. TUS currently manages over 150 GWh under flex‑management programmes, proving that sophisticated volume‑based contracts can be administered at scale while delivering savings that beat supplier forecasts by around 20 %. ## Contract mechanics ### Period choices – monthly, quarterly, seasonal The contract period defines the granularity at which volume commitments are measured. * **Monthly** – best for businesses with tight production schedules (e.g., food processing) where demand can be forecasted to within ±5 %. * **Quarterly** – suits most office‑based or mixed‑use portfolios, balancing forecasting effort with price certainty. * **Seasonal** – aligns with natural demand cycles (winter heating, summer cooling) and is often paired with a “baseline” tranche that covers the bulk of annual consumption. Choosing the right period is a trade‑off between forecasting accuracy and administrative overhead. A mis‑aligned period can trigger unnecessary penalties or force the business to purchase excess volume at spot rates. ### Tranches, caps and triggers A multipurchase contract typically comprises several **tranches** – each a volume band with its own price. * **Base tranche** – covers the expected core demand (e.g., 60 % of annual forecast). Price is usually the lowest tier because the supplier has certainty of volume. * **Flex tranche** – captures the remaining 40 % and is priced higher, reflecting the risk the supplier bears. * **Cap** – a maximum price the buyer will pay for any volume exceeding the flex tranche. Caps protect against extreme market spikes. * **Trigger** – a predefined market event (e.g., spot price > £120/MWh for three consecutive days) that automatically moves excess volume into the capped tier. By structuring caps and triggers, the buyer can limit exposure while giving the supplier an incentive to manage supply risk. ### When to fix non‑commodity components Non‑commodity components include network charges (DUoS, TNUoS), renewable obligation certificates (RO), and any ancillary services. Fixing these early can lock in a predictable total cost of ownership, but it also removes the ability to benefit from future regulatory changes (e.g., a reduction in REGO rates). The optimal timing is: 1. **Before the contract start date** – if the business has a stable load profile and wants a single‑line invoice. 2. **After the first 12 months** – once actual consumption data validates the forecast, allowing a renegotiation of network charge allocations. ## Worked example – 3 GWh annual portfolio Assume a manufacturing firm with the following profile: * Annual demand: 3 GWh (≈8,220 MWh per month on average). * Seasonal split: 40 % winter (Nov‑Mar), 30 % summer (Jun‑Aug), 30 % shoulder. * Market reference price: £55/MWh (spot average 2024 Q2). * Desired price certainty: 20 % below spot for base volume. ### Step 1 – Define periods and tranches * **Period**: Quarterly, to match production planning. * **Base tranche**: 60 % of forecast = 4,932 MWh per year (≈1,233 MWh per quarter). * **Flex tranche**: remaining 40 % = 3,288 MWh per year (≈822 MWh per quarter). ### Step 2 – Set price tiers * **Base price**: £44/MWh (20 % discount to spot). * **Flex price**: £58/MWh (≈5 % premium to spot, reflecting risk). * **Cap price**: £85/MWh (protects against extreme spikes). ### Step 3 – Define trigger If the quarterly average spot price exceeds £120/MWh for two consecutive weeks, any volume above the flex tranche moves to the cap tier. ### Step 4 – Calculate annual cost under three scenarios | Scenario | Spot average | Volume in base | Volume in flex | Volume in cap | Total cost | |---|---|---|---|---|---| | **A – Stable market** | £55/MWh | 4,932 MWh @ £44 = £217,008 | 3,288 MWh @ £58 = £190,704 | 0 | **£407,712** | | **B – Moderate spike** (quarterly spot £115/MWh) | £115/MWh | 4,932 MWh @ £44 = £217,008 | 2,500 MWh @ £58 = £145,000 | 788 MWh @ £85 = £66,980 | **£428,988** | | **C – Extreme spike** (quarterly spot £130/MWh, trigger hit) | £130/MWh | 4,932 MWh @ £44 = £217,008 | 2,000 MWh @ £58 = £116,000 | 1,288 MWh @ £85 = £109,480 | **£442,488** | Even in the worst‑case scenario the contract caps total spend at roughly £442k, compared with an unhedged spot cost of 3 GWh × £130/MWh = £390k – a modest premium for certainty, but the firm avoids the risk of a further price surge. ## Risk and optimisation * **Forecast accuracy** – The base tranche should be set using a rolling 12‑month average, updated quarterly. TUS’s flex‑management platform can automate this, reducing the chance of over‑commitment. * **Supplier selection** – With a 30‑plus supplier panel, the buyer can benchmark base‑price discounts. In the last 12 months TUS‑managed contracts beat supplier projections by 20 % on average. * **Regulatory impact** – Upcoming changes to the Capacity Market and potential adjustments to the CCL could affect the value of the cap tier. Embedding a review clause at the 12‑month mark allows the contract to be re‑priced in line with new policy. * **Technology integration** – Linking the contract to a real‑time energy management system (EMS) enables automatic re‑allocation of excess flex volume to on‑site generation or storage, further reducing exposure. ## Bottom line Multipurchase contracts give UK businesses with 1‑5 GWh of demand a pragmatic blend of price certainty and operational flexibility. By selecting the appropriate period, structuring tranches with sensible caps and triggers, and timing the fixation of non‑commodity components, finance directors can lock in savings that sit comfortably within SECR reporting requirements while preserving the ability to adapt to market or regulatory shifts. A disciplined forecasting process, supported by TUS’s portfolio‑wide data, turns the contract from a simple purchase into a strategic asset. Frequently asked questions: Q: What size of portfolio is best suited to a multipurchase contract? A: Businesses with an annual demand of 1‑5 GWh benefit most, as the volume is large enough to negotiate tiered pricing but small enough to retain flexibility without a full‑scale PPA. Q: How often should the volume forecast be updated? A: Quarterly updates are standard; using a rolling 12‑month average reduces the risk of over‑ or under‑committing to the base tranche. Q: Can network charges be fixed within a multipurchase contract? A: Yes, they can be fixed at contract start for invoicing simplicity, but many firms renegotiate after the first year to capture any changes in DUoS/TNUoS rates. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-10 Category: procurement Published: 2026-08-05 Summary: Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price bands while retaining flexibility to adjust volumes as market conditions change. This article explains period choices, tranche structures, caps, triggers and the optimal moment to fix non‑commodity components, illustrated with a realistic UK pricing example. ## Core thesis Multipurchase contracts are a middle ground between full spot‑market exposure and a rigid fixed‑price supply agreement. For UK firms that consume between 1 and 5 GWh a year, they provide cost certainty for the bulk of the bill while preserving the ability to benefit from favourable market moves. The key is to design the contract architecture – periods, tranches, caps and triggers – so that the commercial risk aligns with the organisation's cash‑flow and sustainability targets. ## How multipurchase contracts are structured ### Period choices – monthly, quarterly or seasonal The contract period determines how often the reference price is reset. A **monthly** period mirrors the Ofgem‑published half‑hourly index and is useful when the business has a tight cash‑flow horizon. **Quarterly** periods smooth short‑term volatility and reduce administrative overhead, while **seasonal** periods (typically winter/summer) align with predictable demand patterns for heating‑intensive or cooling‑intensive sites. Choosing the period involves balancing two factors: 1. **Price risk exposure** – shorter periods expose the buyer to more spot‑price swings. 2. **Operational simplicity** – longer periods mean fewer reconciliations and less data handling. For a 3 GWh portfolio, a quarterly approach often delivers the best trade‑off, delivering a 5‑10 % reduction in administrative cost without materially increasing price risk. ### Tranches and volume bands A multipurchase contract is usually broken into **tranches** – discrete volume bands that each have its own price ceiling and floor. Typical tranche design for a 2 GWh annual demand might be: - **Tranche A:** 0‑500 MWh at a fixed price of £45 /MWh (cap). - **Tranche B:** 501‑1 500 MWh at a variable price linked to the Ofgem Half‑Hourly Index (HHI) with a 10 % uplift. - **Tranche C:** 1 501‑2 000 MWh at a market‑linked price plus a 5 % premium. The purpose of tranches is twofold: they protect the buyer from extreme price spikes on the bulk of consumption, and they allow the supplier to recover higher costs on the tail end of usage where demand is less predictable. ### Caps, floors and triggers **Caps** set an upper bound on the price payable for a tranche. **Floors** protect the supplier from unreasonably low market prices. **Triggers** are pre‑agreed events – such as a 20 % swing in the HHI over a rolling 12‑month window – that automatically shift the contract from a fixed to a variable component or vice‑versa. A practical example: if the HHI exceeds £80 /MWh for three consecutive months, a trigger could move the remaining volume of Tranche B into a market‑linked price with a 5 % discount, thereby sharing upside with the buyer. ## When to fix non‑commodity components Non‑commodity components include Transmission Network Use of System (TNUoS), Distribution Use of System (DUoS), Climate Change Levy (CCL), Renewable Obligation Certificates (RO) and any ancillary services. Fixing these elements early can lock in regulatory risk, especially under **SECR** reporting obligations where the UK carbon price floor (CP‑floor) is volatile. **Guideline:** lock in TNUoS and DUoS rates at contract signing if the forecasted network charge trajectory is expected to rise more than 3 % annually – a scenario that has been common since the 2022 network cost review. Conversely, keep the CCL variable if the business expects to reduce its carbon intensity and benefit from the **Carbon Price Support** reductions. ## Worked example – realistic UK pricing assumptions ### Assumptions - Annual consumption: 2 GWh (2 000 MWh) - Contract period: quarterly - Tranche design as above (A = 0‑500 MWh, B = 501‑1 500 MWh, C = 1 501‑2 000 MWh) - Fixed price for Tranche A: £45 /MWh (cap) - HHI average Q1‑Q4 2024 forecast: £55 /MWh - Variable uplift for Tranche B: 10 % of HHI - Variable premium for Tranche C: 5 % of HHI - Non‑commodity fixed components: TNUoS £5 /MWh, DUoS £2 /MWh, CCL £0.60 /MWh (variable) - Discount trigger: if HHI > £80 /MWh for three months, apply 5 % discount on Tranche B variable price. ### Cost calculation **Tranche A (0‑500 MWh)** - Energy cost: 500 MWh × £45 = £22,500 - Network & levy: 500 MWh × (£5+£2+£0.60) = £3,800 - Total Tranche A: **£26,300** **Tranche B (501‑1 500 MWh – 1 000 MWh)** - Variable price: £55 × 1.10 = £60.50 /MWh - Energy cost: 1 000 MWh × £60.50 = £60,500 - Network & levy: 1 000 MWh × (£5+£2+£0.60) = £7,600 - Total Tranche B: **£68,100** **Tranche C (1 501‑2 000 MWh – 500 MWh)** - Variable price: £55 × 1.05 = £57.75 /MWh - Energy cost: 500 MWh × £57.75 = £28,875 - Network & levy: 500 MWh × (£5+£2+£0.60) = £3,800 - Total Tranche C: **£32,675** **Annual contract total** = £26,300 + £68,100 + £32,675 = **£127,075** ### Sensitivity to a trigger event If the HHI spikes to £85 /MWh for three months, the trigger applies a 5 % discount on Tranche B: - New variable price: £85 × 1.10 × 0.95 = £88.85 /MWh - Revised Tranche B energy cost: 1 000 MWh × £88.85 = £88,850 - Revised total = £26,300 + £88,850 + £32,675 = **£147,825** The trigger protects the buyer from a larger swing (the contract cost rises by ~16 % rather than the full market move of ~55 %). This illustrates how well‑designed caps and triggers can balance risk and reward. ## Leveraging TUS expertise TUS manages **150+ GWh** of flex‑enabled demand, giving us a granular view of how volume tranches behave across the UK market. Our **30+ supplier panel** enables us to negotiate caps that are, on average, **20 % lower than supplier projections** over the past 12 months. Through the **Yolk portal**, clients can monitor tranche utilisation in real time and benchmark against the **27 % average switching saving** achieved by our customers. ## Regulatory context - **Ofgem’s Half‑Hourly Index (HHI)** is the reference for most variable components. - **SECR** reporting obliges large organisations to disclose energy‑related carbon emissions, making fixed non‑commodity components attractive for predictable carbon accounting. - **Capacity Market** and **CfD** schemes influence wholesale price baselines; a multipurchase contract that references HHI automatically incorporates these mechanisms. - **TNUoS** and **DUoS** tariffs are set by **NESO** (formerly NESO) and are reviewed annually – fixing them at contract start can avoid the average 3‑4 % annual increase observed since 2021. ## Implementation checklist 1. **Map annual demand** and segment into logical tranches. 2. **Select period** (monthly/quarterly/seasonal) based on cash‑flow and operational capacity. 3. **Define caps, floors and triggers** in line with market volatility expectations. 4. **Decide which non‑commodity components to fix** – use regulatory forecasts for TNUoS/DUoS. 5. **Run a pricing simulation** (as above) to quantify upside/downside risk. 6. **Engage a multi‑supplier panel** – TUS can source at least three competitive offers. 7. **Deploy the Yolk portal** for ongoing monitoring and optimisation. ## Bottom line Multipurchase contracts give UK businesses with modest energy footprints a pragmatic way to lock in a core cost base while still capturing market upside. By carefully selecting periods, tranches, caps and triggers – and by fixing the right non‑commodity components – organisations can reduce price volatility by up to 15 % and achieve a payback on optimisation activities within two to three years. Leveraging TUS’s extensive flex‑management experience and supplier network further sharpens the commercial outcome. Frequently asked questions: Q: What size of portfolio is best suited to a multipurchase contract? A: Businesses consuming between 1 GWh and 5 GWh annually typically see the greatest benefit, as the contract balances price certainty with enough volume to negotiate favourable tranche caps. Q: How often should the reference price be reset? A: Quarterly periods are a common sweet spot for 1‑5 GWh portfolios, offering a manageable administrative load while limiting exposure to short‑term spot spikes. Q: Can I fix network charges within a multipurchase deal? A: Yes. Fixing TNUoS and DUoS at contract signing is advisable when forecasts show a >3 % annual increase, which has been the trend since the 2022 network cost review. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-9 Category: procurement Published: 2026-08-04 Summary: Multipurchase contracts let organisations with 1‑5 GWh of annual demand lock in price bands while retaining flexibility to adjust volumes as market conditions change. This article explains period choices, tranche structures, caps, triggers and the optimal moment to fix non‑commodity components, illustrated with a realistic UK pricing example. ## Core thesis Multipurchase contracts are a middle ground between full spot‑market exposure and a rigid fixed‑price supply agreement. For UK firms that consume between 1 and 5 GWh a year, they provide cost certainty for the bulk of the bill while preserving the ability to benefit from favourable market moves. The key is to design the contract architecture – periods, tranches, caps and triggers – so that the commercial risk aligns with the organisation's cash‑flow and sustainability targets. ## How multipurchase contracts are structured ### Period choices – monthly, quarterly or seasonal The contract period determines how often the reference price is reset. A **monthly** period mirrors the Ofgem‑published half‑hourly index and is useful when the business has a tight cash‑flow horizon. **Quarterly** periods smooth short‑term volatility and reduce administrative overhead, while **seasonal** periods (typically winter/summer) align with predictable demand patterns for heating‑intensive or cooling‑intensive sites. Choosing the period involves balancing two factors: 1. **Price risk exposure** – shorter periods expose the buyer to more spot‑price swings. 2. **Operational simplicity** – longer periods mean fewer reconciliations and less data handling. For a 3 GWh portfolio, a quarterly approach often delivers the best trade‑off, delivering a 5‑10 % reduction in administrative cost without materially increasing price risk. ### Tranches and volume bands A multipurchase contract is usually broken into **tranches** – discrete volume bands that each have its own price ceiling and floor. Typical tranche design for a 2 GWh annual demand might be: - **Tranche A:** 0‑500 MWh at a fixed price of £45 /MWh (cap). - **Tranche B:** 501‑1 500 MWh at a variable price linked to the Ofgem Half‑Hourly Index (HHI) with a 10 % uplift. - **Tranche C:** 1 501‑2 000 MWh at a market‑linked price plus a 5 % premium. The purpose of tranches is twofold: they protect the buyer from extreme price spikes on the bulk of consumption, and they allow the supplier to recover higher costs on the tail end of usage where demand is less predictable. ### Caps, floors and triggers **Caps** set an upper bound on the price payable for a tranche. **Floors** protect the supplier from unreasonably low market prices. **Triggers** are pre‑agreed events – such as a 20 % swing in the HHI over a rolling 12‑month window – that automatically shift the contract from a fixed to a variable component or vice‑versa. A practical example: if the HHI exceeds £80 /MWh for three consecutive months, a trigger could move the remaining volume of Tranche B into a market‑linked price with a 5 % discount, thereby sharing upside with the buyer. ## When to fix non‑commodity components Non‑commodity components include Transmission Network Use of System (TNUoS), Distribution Use of System (DUoS), Climate Change Levy (CCL), Renewable Obligation Certificates (RO) and any ancillary services. Fixing these elements early can lock in regulatory risk, especially under **SECR** reporting obligations where the UK carbon price floor (CP‑floor) is volatile. **Guideline:** lock in TNUoS and DUoS rates at contract signing if the forecasted network charge trajectory is expected to rise more than 3 % annually – a scenario that has been common since the 2022 network cost review. Conversely, keep the CCL variable if the business expects to reduce its carbon intensity and benefit from the **Carbon Price Support** reductions. ## Worked example – realistic UK pricing assumptions ### Assumptions - Annual consumption: 2 GWh (2 000 MWh) - Contract period: quarterly - Tranche design as above (A = 0‑500 MWh, B = 501‑1 500 MWh, C = 1 501‑2 000 MWh) - Fixed price for Tranche A: £45 /MWh (cap) - HHI average Q1‑Q4 2024 forecast: £55 /MWh - Variable uplift for Tranche B: 10 % of HHI - Variable premium for Tranche C: 5 % of HHI - Non‑commodity fixed components: TNUoS £5 /MWh, DUoS £2 /MWh, CCL £0.60 /MWh (variable) - Discount trigger: if HHI > £80 /MWh for three months, apply 5 % discount on Tranche B variable price. ### Cost calculation **Tranche A (0‑500 MWh)** - Energy cost: 500 MWh × £45 = £22,500 - Network & levy: 500 MWh × (£5+£2+£0.60) = £3,800 - Total Tranche A: **£26,300** **Tranche B (501‑1 500 MWh – 1 000 MWh)** - Variable price: £55 × 1.10 = £60.50 /MWh - Energy cost: 1 000 MWh × £60.50 = £60,500 - Network & levy: 1 000 MWh × (£5+£2+£0.60) = £7,600 - Total Tranche B: **£68,100** **Tranche C (1 501‑2 000 MWh – 500 MWh)** - Variable price: £55 × 1.05 = £57.75 /MWh - Energy cost: 500 MWh × £57.75 = £28,875 - Network & levy: 500 MWh × (£5+£2+£0.60) = £3,800 - Total Tranche C: **£32,675** **Annual contract total** = £26,300 + £68,100 + £32,675 = **£127,075** ### Sensitivity to a trigger event If the HHI spikes to £85 /MWh for three months, the trigger applies a 5 % discount on Tranche B: - New variable price: £85 × 1.10 × 0.95 = £88.85 /MWh - Revised Tranche B energy cost: 1 000 MWh × £88.85 = £88,850 - Revised total = £26,300 + £88,850 + £32,675 = **£147,825** The trigger protects the buyer from a larger swing (the contract cost rises by ~16 % rather than the full market move of ~55 %). This illustrates how well‑designed caps and triggers can balance risk and reward. ## Leveraging TUS expertise TUS manages **150+ GWh** of flex‑enabled demand, giving us a granular view of how volume tranches behave across the UK market. Our **30+ supplier panel** enables us to negotiate caps that are, on average, **20 % lower than supplier projections** over the past 12 months. Through the **Yolk portal**, clients can monitor tranche utilisation in real time and benchmark against the **27 % average switching saving** achieved by our customers. ## Regulatory context - **Ofgem’s Half‑Hourly Index (HHI)** is the reference for most variable components. - **SECR** reporting obliges large organisations to disclose energy‑related carbon emissions, making fixed non‑commodity components attractive for predictable carbon accounting. - **Capacity Market** and **CfD** schemes influence wholesale price baselines; a multipurchase contract that references HHI automatically incorporates these mechanisms. - **TNUoS** and **DUoS** tariffs are set by **NESO** (formerly NESO) and are reviewed annually – fixing them at contract start can avoid the average 3‑4 % annual increase observed since 2021. ## Implementation checklist 1. **Map annual demand** and segment into logical tranches. 2. **Select period** (monthly/quarterly/seasonal) based on cash‑flow and operational capacity. 3. **Define caps, floors and triggers** in line with market volatility expectations. 4. **Decide which non‑commodity components to fix** – use regulatory forecasts for TNUoS/DUoS. 5. **Run a pricing simulation** (as above) to quantify upside/downside risk. 6. **Engage a multi‑supplier panel** – TUS can source at least three competitive offers. 7. **Deploy the Yolk portal** for ongoing monitoring and optimisation. ## Bottom line Multipurchase contracts give UK businesses with modest energy footprints a pragmatic way to lock in a core cost base while still capturing market upside. By carefully selecting periods, tranches, caps and triggers – and by fixing the right non‑commodity components – organisations can reduce price volatility by up to 15 % and achieve a payback on optimisation activities within two to three years. Leveraging TUS’s extensive flex‑management experience and supplier network further sharpens the commercial outcome. Frequently asked questions: Q: What size of portfolio is best suited to a multipurchase contract? A: Businesses consuming between 1 GWh and 5 GWh annually typically see the greatest benefit, as the contract balances price certainty with enough volume to negotiate favourable tranche caps. Q: How often should the reference price be reset? A: Quarterly periods are a common sweet spot for 1‑5 GWh portfolios, offering a manageable administrative load while limiting exposure to short‑term spot spikes. Q: Can I fix network charges within a multipurchase deal? A: Yes. Fixing TNUoS and DUoS at contract signing is advisable when forecasts show a >3 % annual increase, which has been the trend since the 2022 network cost review. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-8 Category: procurement Published: 2026-08-03 Summary: Multipurchase contracts let UK firms with 1‑5 GWh annual demand lock in price bands while retaining flexibility to trade volume. This guide explains period choices, tranche design, caps, triggers and when to fix non‑commodity components, ending with a realistic worked example. ## Thesis Multipurchase contracts are a middle ground between a pure spot‑market exposure and a long‑term fixed‑price deal. For businesses that consume between 1 and 5 GWh a year, they provide cost certainty on a portion of the bill while preserving the ability to benefit from market dips. The key is to structure the contract so that caps, triggers and periodicity align with your consumption pattern and risk appetite. ## Understanding multipurchase contracts Multipurchase contracts, sometimes called "volume‑based contracts" or "flex‑contracts", combine a pre‑agreed price band for a defined volume with the freedom to trade any excess or shortfall on the wholesale market. The contract typically covers a calendar year, broken into settlement periods – monthly, quarterly or seasonal – that match the business's load profile. ### Why they matter for 1‑5 GWh portfolios * **Risk management** – A 20 % swing in wholesale prices can translate into £10‑£30 k of annual variance for a 2 GWh portfolio. A multipurchase contract caps that exposure. * **Regulatory alignment** – Under the SECR (Streamlined Energy and Carbon Reporting) and Ofgem’s Market‑wide Half‑Hourly Settlement (MHHS) rules, firms must demonstrate a credible procurement strategy. A structured multipurchase contract satisfies both cost‑control and compliance objectives. * **Operational flexibility** – Companies can adjust consumption patterns (e.g., shift load to off‑peak) without renegotiating the entire contract. ## Choosing the right periodicity Period choices dictate how often the contracted volume is reconciled against actual consumption. | Periodicity | Typical use‑case | Pros | Cons | |---|---|---|---| | **Monthly** | Businesses with relatively stable, evenly spread demand. | Faster correction of over‑/under‑runs; aligns with most accounting cycles. | Higher administrative overhead. | **Quarterly** | Seasonal manufacturers or retailers with clear quarterly peaks. | Simpler reporting; lower transaction cost. | Larger variance risk within the quarter. | **Seasonal** | Companies with pronounced winter/summer splits (e.g., cold‑storage, data centres with seasonal cooling). | Mirrors natural demand swings; easier to set caps. | Less granularity can mask short‑term spikes. The choice should reflect the granularity of your internal metering data and the volatility of your load profile. For a 3 GWh portfolio with a clear winter peak, a seasonal split (winter vs. summer) often yields the best balance. ## Structuring tranches, caps and triggers A tranche is a block of volume purchased at a pre‑agreed price. Multiple tranches can be layered to create a stepped price curve. ### Tranche design 1. **Base tranche** – Covers the core consumption (e.g., 60 % of forecast). Fixed price, low risk. 2. **Flex tranche** – Covers the remaining 40 % and is priced at a band (e.g., £45‑£55/MWh). This tranche is where caps and triggers operate. ### Caps and triggers * **Upper cap** – Maximum price you will pay for the flex tranche. If the market price exceeds the cap, the supplier absorbs the excess. * **Lower trigger** – Minimum price at which the supplier can request you to purchase additional volume (often called a "call‑option"). * **Volume caps** – Limits on how much of the flex tranche can be called in a period. Typical caps are 10‑20 % of the tranche volume per month. These mechanisms protect both parties: you avoid runaway costs, and the supplier retains a revenue floor. ## When to fix non‑commodity components Non‑commodity components include network charges (DUoS, TNUoS), capacity market obligations, and ancillary services. Fixing them early can simplify budgeting, but they are subject to regulatory changes. * **Network tariffs** – Often reviewed annually by Ofgem. Locking them in for the contract year reduces surprise bills. * **Capacity market** – For firms with demand‑side response capability, fixing the capacity charge (currently £12‑£15/MWh) can be advantageous. * **Carbon price floor (CCF)** – Fixed for the contract year under the CCL (Carbon Charge Levy) regime. A pragmatic approach is to fix the majority of non‑commodity items for the first 12‑month horizon, then review at each renewal. ## Worked example – realistic UK pricing assumptions **Company profile**: Manufacturing firm, 3 GWh annual electricity use, split 55 % winter (Oct‑Mar) and 45 % summer (Apr‑Sep). Desired contract: seasonal periods, two tranches. ### Step 1 – Forecast consumption * Winter forecast: 1.65 GWh (≈ 275 MWh/month) * Summer forecast: 1.35 GWh (≈ 225 MWh/month) ### Step 2 – Define tranches | Season | Base tranche | Volume | Fixed price | Flex tranche | Volume | Price band | |---|---|---|---|---|---|---| | Winter | 60 % | 990 MWh | £48/MWh | 40 % | 660 MWh | £45‑£55/MWh | | Summer | 60 % | 810 MWh | £45/MWh | 40 % | 540 MWh | £42‑£52/MWh | ### Step 3 – Set caps and triggers * Upper cap: £55/MWh (winter), £52/MWh (summer) * Lower trigger: £45/MWh (winter), £42/MWh (summer) * Volume call cap: 15 % of flex tranche per month. ### Step 4 – Fix non‑commodity components * DUoS/TNUoS: Fixed at £15/MWh for the year (based on 2025 tariffs). * Capacity charge: Fixed at £13/MWh. * CCF: Fixed at £30/MWh. ### Step 5 – Simulated market outcomes (2025‑26) | Month | Spot price | Base tranche cost | Flex tranche cost (capped) | Total electricity cost | |---|---|---|---|---| | Jan | £60 | 990 MWh × £48 = £47,520 | 660 MWh × £55 (cap) = £36,300 | £83,820 | | Feb | £42 | £47,520 | 660 MWh × £45 (trigger) = £29,700 | £77,220 | | Mar | £38 | £47,520 | 660 MWh × £38 = £25,080 | £72,600 | | … | … | … | … | … | Summing the 12 months yields an annual electricity cost of **£1.02 million**, compared with a pure spot exposure of £1.15 million in the same simulated market. The contract delivered a **~11 % saving**, well within the typical 5‑15 % saving range achieved by TUS’s voltage optimisation projects, which also enjoy a 2‑3 year payback. ### Step 6 – Risk‑adjusted outcome * **Cost certainty** – Upper caps limit exposure to extreme price spikes. * **Flexibility** – If the spot price falls below the lower trigger, the firm can voluntarily purchase additional volume at the lower price, improving the overall margin. * **Regulatory compliance** – The contract satisfies SECR procurement expectations and aligns with Ofgem’s guidance on flexible procurement. ## Operational considerations 1. **Data quality** – Accurate half‑hourly consumption data is essential for reconciling tranches. TUS’s Yolk portal provides a free dashboard that integrates half‑hourly data and highlights variance, helping firms achieve the 27 % average switching saving reported across our client base. 2. **Supplier panel** – Leveraging a 30‑plus supplier panel reduces the risk of over‑reliance on a single provider and improves negotiation leverage. TUS has consistently beaten supplier projections by 20 % in the last 12 months, demonstrating the value of a diversified panel. 3. **Flex management** – With over 150 GWh under flex management, TUS can dynamically adjust tranche utilisation, ensuring that caps are respected while maximising market opportunities. ## Bottom line Multipurchase contracts give UK businesses with modest electricity demand a pragmatic way to lock in cost certainty while retaining market upside. By selecting the appropriate period (monthly, quarterly or seasonal), structuring base and flex tranches, and applying sensible caps and triggers, firms can achieve 5‑15 % savings with a payback horizon of two to three years. Coupled with robust data platforms like Yolk and a wide supplier panel, the approach aligns with regulatory expectations and delivers tangible financial benefits. Frequently asked questions: Q: What size of portfolio is suitable for a multipurchase contract? A: Typically firms consuming between 1 GWh and 5 GWh per year benefit most, as the contract balances price certainty with flexibility without the administrative burden of larger, bespoke deals. Q: How often should the contract periods be reviewed? A: Review at least annually, coinciding with the regulatory tariff review cycle (DUoS/TNUoS) and any significant changes in the firm’s load profile. Q: Can I combine a multipurchase contract with voltage optimisation? A: Yes. Voltage optimisation can deliver an additional 5‑15 % reduction in kWh consumption, which compounds the savings achieved through the multipurchase price band. --- ### A practical deep dive into multipurchase contracts for UK businesses Source: https://tus.group/articles/multipurchase-deep-dive-7 Category: procurement Published: 2026-08-02 Summary: Multipurchase contracts let UK firms with 1‑5 GWh annual demand lock in price bands while retaining flexibility to trade volume. This guide explains period choices, tranche design, caps, triggers and when to fix non‑commodity components, ending with a realistic worked example. ## Thesis Multipurchase contracts are a middle ground between a pure spot‑market exposure and a long‑term fixed‑price deal. For businesses that consume between 1 and 5 GWh a year, they provide cost certainty on a portion of the bill while preserving the ability to benefit from market dips. The key is to structure the contract so that caps, triggers and periodicity align with your consumption pattern and risk appetite. ## Understanding multipurchase contracts Multipurchase contracts, sometimes called "volume‑based contracts" or "flex‑contracts", combine a pre‑agreed price band for a defined volume with the freedom to trade any excess or shortfall on the wholesale market. The contract typically covers a calendar year, broken into settlement periods – monthly, quarterly or seasonal – that match the business's load profile. ### Why they matter for 1‑5 GWh portfolios * **Risk management** – A 20 % swing in wholesale prices can translate into £10‑£30 k of annual variance for a 2 GWh portfolio. A multipurchase contract caps that exposure. * **Regulatory alignment** – Under the SECR (Streamlined Energy and Carbon Reporting) and Ofgem’s Market‑wide Half‑Hourly Settlement (MHHS) rules, firms must demonstrate a credible procurement strategy. A structured multipurchase contract satisfies both cost‑control and compliance objectives. * **Operational flexibility** – Companies can adjust consumption patterns (e.g., shift load to off‑peak) without renegotiating the entire contract. ## Choosing the right periodicity Period choices dictate how often the contracted volume is reconciled against actual consumption. | Periodicity | Typical use‑case | Pros | Cons | |---|---|---|---| | **Monthly** | Businesses with relatively stable, evenly spread demand. | Faster correction of over‑/under‑runs; aligns with most accounting cycles. | Higher administrative overhead. | **Quarterly** | Seasonal manufacturers or retailers with clear quarterly peaks. | Simpler reporting; lower transaction cost. | Larger variance risk within the quarter. | **Seasonal** | Companies with pronounced winter/summer splits (e.g., cold‑storage, data centres with seasonal cooling). | Mirrors natural demand swings; easier to set caps. | Less granularity can mask short‑term spikes. The choice should reflect the granularity of your internal metering data and the volatility of your load profile. For a 3 GWh portfolio with a clear winter peak, a seasonal split (winter vs. summer) often yields the best balance. ## Structuring tranches, caps and triggers A tranche is a block of volume purchased at a pre‑agreed price. Multiple tranches can be layered to create a stepped price curve. ### Tranche design 1. **Base tranche** – Covers the core consumption (e.g., 60 % of forecast). Fixed price, low risk. 2. **Flex tranche** – Covers the remaining 40 % and is priced at a band (e.g., £45‑£55/MWh). This tranche is where caps and triggers operate. ### Caps and triggers * **Upper cap** – Maximum price you will pay for the flex tranche. If the market price exceeds the cap, the supplier absorbs the excess. * **Lower trigger** – Minimum price at which the supplier can request you to purchase additional volume (often called a "call‑option"). * **Volume caps** – Limits on how much of the flex tranche can be called in a period. Typical caps are 10‑20 % of the tranche volume per month. These mechanisms protect both parties: you avoid runaway costs, and the supplier retains a revenue floor. ## When to fix non‑commodity components Non‑commodity components include network charges (DUoS, TNUoS), capacity market obligations, and ancillary services. Fixing them early can simplify budgeting, but they are subject to regulatory changes. * **Network tariffs** – Often reviewed annually by Ofgem. Locking them in for the contract year reduces surprise bills. * **Capacity market** – For firms with demand‑side response capability, fixing the capacity charge (currently £12‑£15/MWh) can be advantageous. * **Carbon price floor (CCF)** – Fixed for the contract year under the CCL (Carbon Charge Levy) regime. A pragmatic approach is to fix the majority of non‑commodity items for the first 12‑month horizon, then review at each renewal. ## Worked example – realistic UK pricing assumptions **Company profile**: Manufacturing firm, 3 GWh annual electricity use, split 55 % winter (Oct‑Mar) and 45 % summer (Apr‑Sep). Desired contract: seasonal periods, two tranches. ### Step 1 – Forecast consumption * Winter forecast: 1.65 GWh (≈ 275 MWh/month) * Summer forecast: 1.35 GWh (≈ 225 MWh/month) ### Step 2 – Define tranches | Season | Base tranche | Volume | Fixed price | Flex tranche | Volume | Price band | |---|---|---|---|---|---|---| | Winter | 60 % | 990 MWh | £48/MWh | 40 % | 660 MWh | £45‑£55/MWh | | Summer | 60 % | 810 MWh | £45/MWh | 40 % | 540 MWh | £42‑£52/MWh | ### Step 3 – Set caps and triggers * Upper cap: £55/MWh (winter), £52/MWh (summer) * Lower trigger: £45/MWh (winter), £42/MWh (summer) * Volume call cap: 15 % of flex tranche per month. ### Step 4 – Fix non‑commodity components * DUoS/TNUoS: Fixed at £15/MWh for the year (based on 2025 tariffs). * Capacity charge: Fixed at £13/MWh. * CCF: Fixed at £30/MWh. ### Step 5 – Simulated market outcomes (2025‑26) | Month | Spot price | Base tranche cost | Flex tranche cost (capped) | Total electricity cost | |---|---|---|---|---| | Jan | £60 | 990 MWh × £48 = £47,520 | 660 MWh × £55 (cap) = £36,300 | £83,820 | | Feb | £42 | £47,520 | 660 MWh × £45 (trigger) = £29,700 | £77,220 | | Mar | £38 | £47,520 | 660 MWh × £38 = £25,080 | £72,600 | | … | … | … | … | … | Summing the 12 months yields an annual electricity cost of **£1.02 million**, compared with a pure spot exposure of £1.15 million in the same simulated market. The contract delivered a **~11 % saving**, well within the typical 5‑15 % saving range achieved by TUS’s voltage optimisation projects, which also enjoy a 2‑3 year payback. ### Step 6 – Risk‑adjusted outcome * **Cost certainty** – Upper caps limit exposure to extreme price spikes. * **Flexibility** – If the spot price falls below the lower trigger, the firm can voluntarily purchase additional volume at the lower price, improving the overall margin. * **Regulatory compliance** – The contract satisfies SECR procurement expectations and aligns with Ofgem’s guidance on flexible procurement. ## Operational considerations 1. **Data quality** – Accurate half‑hourly consumption data is essential for reconciling tranches. TUS’s Yolk portal provides a free dashboard that integrates half‑hourly data and highlights variance, helping firms achieve the 27 % average switching saving reported across our client base. 2. **Supplier panel** – Leveraging a 30‑plus supplier panel reduces the risk of over‑reliance on a single provider and improves negotiation leverage. TUS has consistently beaten supplier projections by 20 % in the last 12 months, demonstrating the value of a diversified panel. 3. **Flex management** – With over 150 GWh under flex management, TUS can dynamically adjust tranche utilisation, ensuring that caps are respected while maximising market opportunities. ## Bottom line Multipurchase contracts give UK businesses with modest electricity demand a pragmatic way to lock in cost certainty while retaining market upside. By selecting the appropriate period (monthly, quarterly or seasonal), structuring base and flex tranches, and applying sensible caps and triggers, firms can achieve 5‑15 % savings with a payback horizon of two to three years. Coupled with robust data platforms like Yolk and a wide supplier panel, the approach aligns with regulatory expectations and delivers tangible financial benefits. Frequently asked questions: Q: What size of portfolio is suitable for a multipurchase contract? A: Typically firms consuming between 1 GWh and 5 GWh per year benefit most, as the contract balances price certainty with flexibility without the administrative burden of larger, bespoke deals. Q: How often should the contract periods be reviewed? A: Review at least annually, coinciding with the regulatory tariff review cycle (DUoS/TNUoS) and any significant changes in the firm’s load profile. Q: Can I combine a multipurchase contract with voltage optimisation? A: Yes. Voltage optimisation can deliver an additional 5‑15 % reduction in kWh consumption, which compounds the savings achieved through the multipurchase price band. --- ### How to structure a Multipurchase contract for UK business energy portfolios Source: https://tus.group/articles/multipurchase-deep-dive-6 Category: procurement Published: 2026-07-16 Summary: Multipurchase contracts let UK businesses fix energy prices across multiple sites or periods, reducing exposure to volatility. For portfolios of 1–5 GWh, they offer flexibility in period choices (monthly, quarterly, seasonal) and tranches, but require careful management of caps, triggers, and non-commodity components. A worked example with current UK pricing assumptions shows how to balance cost certainty with operational flexibility. ## **Multipurchase contracts offer a pragmatic middle ground for UK businesses hedging 1–5 GWh portfolios—neither the rigid lock-in of long-term PPAs nor the volatility of spot markets.** These contracts allow you to fix prices across multiple sites, time periods, or both, while retaining some agility. For businesses managing portfolios in this range, the challenge lies in structuring the contract to align with your cash flow, risk tolerance, and operational needs—without overcomplicating procurement. TUS manages over **150 GWh of flexible energy contracts**, including Multipurchase structures for mid-sized portfolios, and we’ve consistently **beaten supplier projections by 20% in the last 12 months** by optimising these trades. This deep dive breaks down how they work, the mechanics of period selection, tranches, caps, and triggers, and when to fix non-commodity components—with a worked example using realistic UK pricing assumptions for 2025. Frequently asked questions: Q: Can I mix fixed and flexible periods in a Multipurchase contract? A: Yes, but it depends on the supplier’s flexibility. Some allow tranches where a portion is fixed (e.g., 60% fixed for 12 months, 40% left flexible for quarterly review). Others may require separate contracts. At TUS, we’ve structured hybrid models for clients with uneven consumption profiles, but the trade-off is often higher admin cost. Q: What happens if my actual usage exceeds the contracted volume? A: Most Multipurchase contracts include a ‘take-or-pay’ clause, where you’re charged for the contracted volume even if unused. However, some suppliers offer ‘volume tolerance’ (e.g., ±10%) or allow you to buy additional volumes at spot rates. Always negotiate this upfront—we’ve seen clients pay **15–20% premiums** on unused volumes when this wasn’t clarified. Q: How do non-commodity costs (e.g., DUoS, TNUoS) fit into a Multipurchase? A: Non-commodity costs can be fixed separately or bundled into the contract. Fixing them reduces volatility but may lock you into outdated network charges. For example, DUoS (Distribution Use of System) charges are rising due to **Ofgem’s RIIO-2** framework, so some clients opt to fix only the commodity price and leave network costs flexible. We recommend a **3–5 year fix for non-commodity costs** if your sites are stable, but shorter terms if you’re expanding. --- ### How to structure a Multipurchase contract for UK business energy portfolios Source: https://tus.group/articles/multipurchase-deep-dive-5 Category: procurement Published: 2026-07-15 Summary: Multipurchase contracts let UK businesses fix energy prices across multiple sites or periods, reducing exposure to volatility. For portfolios of 1–5 GWh, they offer flexibility in period choices (monthly, quarterly, seasonal) and tranches, but require careful management of caps, triggers, and non-commodity components. A worked example with current UK pricing assumptions shows how to balance cost certainty with operational flexibility. ## **Multipurchase contracts offer a pragmatic middle ground for UK businesses hedging 1–5 GWh portfolios—neither the rigid lock-in of long-term PPAs nor the volatility of spot markets.** These contracts allow you to fix prices across multiple sites, time periods, or both, while retaining some agility. For businesses managing portfolios in this range, the challenge lies in structuring the contract to align with your cash flow, risk tolerance, and operational needs—without overcomplicating procurement. TUS manages over **150 GWh of flexible energy contracts**, including Multipurchase structures for mid-sized portfolios, and we’ve consistently **beaten supplier projections by 20% in the last 12 months** by optimising these trades. This deep dive breaks down how they work, the mechanics of period selection, tranches, caps, and triggers, and when to fix non-commodity components—with a worked example using realistic UK pricing assumptions for 2025. Frequently asked questions: Q: Can I mix fixed and flexible periods in a Multipurchase contract? A: Yes, but it depends on the supplier’s flexibility. Some allow tranches where a portion is fixed (e.g., 60% fixed for 12 months, 40% left flexible for quarterly review). Others may require separate contracts. At TUS, we’ve structured hybrid models for clients with uneven consumption profiles, but the trade-off is often higher admin cost. Q: What happens if my actual usage exceeds the contracted volume? A: Most Multipurchase contracts include a ‘take-or-pay’ clause, where you’re charged for the contracted volume even if unused. However, some suppliers offer ‘volume tolerance’ (e.g., ±10%) or allow you to buy additional volumes at spot rates. Always negotiate this upfront—we’ve seen clients pay **15–20% premiums** on unused volumes when this wasn’t clarified. Q: How do non-commodity costs (e.g., DUoS, TNUoS) fit into a Multipurchase? A: Non-commodity costs can be fixed separately or bundled into the contract. Fixing them reduces volatility but may lock you into outdated network charges. For example, DUoS (Distribution Use of System) charges are rising due to **Ofgem’s RIIO-2** framework, so some clients opt to fix only the commodity price and leave network costs flexible. We recommend a **3–5 year fix for non-commodity costs** if your sites are stable, but shorter terms if you’re expanding. --- ### Understanding Multipurchase Contracts for UK Energy Procurement Source: https://tus.group/articles/multipurchase-deep-dive-4 Category: procurement Published: 2026-07-10 Summary: Multipurchase contracts offer UK businesses with 1–5 GWh energy portfolios a structured way to manage procurement across multiple periods and volumes. This article explains how tranches, period choices, caps, and triggers work, with a practical example using realistic UK pricing and regulatory context. It also covers when to fix non-commodity components to avoid exposure. ## The Strategic Value of Multipurchase Contracts for Mid-Sized UK Energy Users For UK businesses with energy consumption between 1 and 5 GWh annually, traditional single-term contracts often fail to balance cost certainty with flexibility. Multipurchase contracts address this by enabling procurement across multiple periods—monthly, quarterly, or seasonal—while allowing volume tranches and embedded risk controls. These contracts are particularly effective when paired with TUS’s 30+ supplier panel and 150+ GWh of active flex management, which consistently beat supplier projections by 20% over the past 12 months. By structuring procurement in tranches, organisations can respond to market volatility without overcommitting capital. ## How Multipurchase Contracts Work: Tranches, Periods, and Triggers Multipurchase contracts divide total energy volume into discrete tranches, each assigned to a specific delivery period—such as monthly or quarterly. This structure enables better cash flow management and allows businesses to align procurement with seasonal demand patterns. For example, a business with a seasonal peak in Q1 can purchase higher volumes during winter months, while reducing exposure in lower-demand periods. Period choice is critical. Monthly procurement offers the highest flexibility but may result in higher average prices due to short-term volatility. Quarterly contracts reduce administrative overhead and can lock in better rates during stable market windows. Seasonal contracts—typically aligned with winter (Oct–Mar) and summer (Apr–Sep)—are effective for businesses with strong seasonal demand curves. These are particularly useful when paired with Ofgem’s Market Hourly Hydrogen System (MHHS) data, which helps forecast peak and off-peak periods. Tranches are not just volume allocations—they also serve as risk control mechanisms. Each tranche can be assigned a price cap and a trigger level. If the market price exceeds the cap during the procurement window, the contract automatically reverts to a pre-agreed fallback rate or triggers a renegotiation clause. This prevents overpayment during price spikes, a common issue in the volatile UK wholesale market. ## Managing Non-Commodity Components: When to Fix and When to Float Non-commodity elements—such as TNUoS (Transmission Network Use of System), DUoS (Distribution Use of System), capacity charges, and environmental levies—represent a significant portion of the total cost. For businesses under 5 GWh, these components are often variable and subject to change based on grid usage and policy updates. The key decision is whether to fix these elements in the contract or leave them floating. Fixing non-commodity components provides cost certainty but may reduce competitiveness if market rates decline. Floating them allows exposure to potential savings but increases budget volatility. For businesses with stable load profiles and predictable usage patterns, fixing non-commodity components in the contract is advisable. This is especially effective when using TUS’s Yolk portal, which provides free access to 27% average switching savings across the UK market. For those with higher variability—such as businesses with variable production cycles or seasonal operations—floating these elements while hedging through a separate contract can yield better long-term outcomes. ## Worked Example: A 3 GWh Business Using a Multipurchase Structure Consider a manufacturing site in the Midlands with a 3 GWh annual consumption profile. The site has a seasonal demand pattern: 1.2 GWh in winter (Oct–Mar), 0.8 GWh in spring (Apr–Jun), 0.6 GWh in summer (Jul–Sep), and 0.4 GWh in autumn (Oct–Dec). The business uses a quarterly multipurchase structure with three tranches: - Q1 (Oct–Dec): 0.9 GWh at a capped price of £75/MWh (cap triggered if market exceeds £80/MWh) - Q2 (Jan–Mar): 1.1 GWh at £72/MWh with a cap at £78/MWh - Q3 (Apr–Jun): 0.8 GWh at £68/MWh with a cap at £75/MWh The non-commodity components are fixed at £18/MWh for TNUoS, £12/MWh for DUoS, and £3/MWh for capacity charges—totaling £33/MWh. These are fixed in the contract, providing full visibility over the total cost. Using TUS’s 30+ supplier panel and historical data, the average market price for Q1 was £79/MWh, which triggered the cap. The contract automatically applied the fallback rate of £75/MWh, saving £0.40/MWh on 0.9 GWh—equating to £360 in savings. In Q2, the market price settled at £75/MWh, slightly above the fixed rate, resulting in a small overpayment. However, the overall structure provided better cost control than a single fixed contract. The total annual cost under this multipurchase structure is £255,000 (3 GWh × £85/MWh), compared to a single fixed contract at £88/MWh, which would have cost £264,000. This represents a 3.4% saving, equivalent to £9,000 annually. ## Regulatory and Market Context Multipurchase contracts operate within the UK’s broader energy market framework. Ofgem’s MHHS provides real-time data on system imbalance prices, which influence short-term procurement decisions. The capacity market, managed by NESO, ensures grid reliability and influences forward pricing for winter contracts. For businesses under 5 GWh, the Capacity Market is not mandatory, but participation in the annual auction can yield additional revenue through capacity payments. Environmental compliance is also relevant. The Carbon Reduction Commitment (CCL) applies to businesses with energy use above 10 GWh, so this 3 GWh site is exempt. However, the Renewable Obligation (RO) and Contracts for Difference (CfD) schemes influence wholesale pricing and are factored into long-term forecasts. The use of REGOs and SEG (Smart Export Guarantee) payments is relevant for businesses with on-site generation, though not applicable here. ## Bottom line Multipurchase contracts offer a practical, scalable solution for UK businesses with 1–5 GWh energy portfolios. By using tranches across monthly, quarterly, or seasonal periods, organisations can manage volatility, reduce exposure to price spikes, and improve budget predictability. Fixing non-commodity components where load profiles are stable improves cost certainty, while using caps and triggers adds resilience. With TUS’s 150+ GWh flex management and 27% average switching savings, businesses can achieve tangible cost reductions without sacrificing flexibility. The key is aligning contract structure with actual demand patterns and market conditions—something that requires detailed analysis, not just price comparison. Frequently asked questions: Q: What is the minimum energy volume required to use a Multipurchase contract? A: Multipurchase contracts are effective for businesses with annual consumption between 1 and 5 GWh. They are not designed for portfolios below 1 GWh, where single-term contracts or direct negotiation may be more efficient. Q: Can I change the period or volume of a tranche after the contract starts? A: Most multipurchase contracts allow for volume adjustments within a predefined window—typically 14 days before the period starts. Changes to the period require renegotiation and are subject to market availability. Q: How does TUS ensure the best price when using the 30+ supplier panel? A: TUS uses real-time market data, historical price trends, and supplier performance metrics to benchmark offers. Our 150+ GWh of active flex management ensures we consistently beat supplier projections by 20% over the past 12 months. --- ### Understanding Multipurchase Contracts for UK Energy Procurement Source: https://tus.group/articles/multipurchase-deep-dive-3 Category: procurement Published: 2026-07-09 Summary: Multipurchase contracts offer UK businesses with 1–5 GWh energy portfolios a structured way to manage procurement across multiple periods and volumes. This article explains how tranches, period choices, caps, and triggers work, with a practical example using realistic UK pricing and regulatory context. It also covers when to fix non-commodity components to avoid exposure. ## The Strategic Value of Multipurchase Contracts for Mid-Sized UK Energy Users For UK businesses with energy consumption between 1 and 5 GWh annually, traditional single-term contracts often fail to balance cost certainty with flexibility. Multipurchase contracts address this by enabling procurement across multiple periods—monthly, quarterly, or seasonal—while allowing volume tranches and embedded risk controls. These contracts are particularly effective when paired with TUS’s 30+ supplier panel and 150+ GWh of active flex management, which consistently beat supplier projections by 20% over the past 12 months. By structuring procurement in tranches, organisations can respond to market volatility without overcommitting capital. ## How Multipurchase Contracts Work: Tranches, Periods, and Triggers Multipurchase contracts divide total energy volume into discrete tranches, each assigned to a specific delivery period—such as monthly or quarterly. This structure enables better cash flow management and allows businesses to align procurement with seasonal demand patterns. For example, a business with a seasonal peak in Q1 can purchase higher volumes during winter months, while reducing exposure in lower-demand periods. Period choice is critical. Monthly procurement offers the highest flexibility but may result in higher average prices due to short-term volatility. Quarterly contracts reduce administrative overhead and can lock in better rates during stable market windows. Seasonal contracts—typically aligned with winter (Oct–Mar) and summer (Apr–Sep)—are effective for businesses with strong seasonal demand curves. These are particularly useful when paired with Ofgem’s Market Hourly Hydrogen System (MHHS) data, which helps forecast peak and off-peak periods. Tranches are not just volume allocations—they also serve as risk control mechanisms. Each tranche can be assigned a price cap and a trigger level. If the market price exceeds the cap during the procurement window, the contract automatically reverts to a pre-agreed fallback rate or triggers a renegotiation clause. This prevents overpayment during price spikes, a common issue in the volatile UK wholesale market. ## Managing Non-Commodity Components: When to Fix and When to Float Non-commodity elements—such as TNUoS (Transmission Network Use of System), DUoS (Distribution Use of System), capacity charges, and environmental levies—represent a significant portion of the total cost. For businesses under 5 GWh, these components are often variable and subject to change based on grid usage and policy updates. The key decision is whether to fix these elements in the contract or leave them floating. Fixing non-commodity components provides cost certainty but may reduce competitiveness if market rates decline. Floating them allows exposure to potential savings but increases budget volatility. For businesses with stable load profiles and predictable usage patterns, fixing non-commodity components in the contract is advisable. This is especially effective when using TUS’s Yolk portal, which provides free access to 27% average switching savings across the UK market. For those with higher variability—such as businesses with variable production cycles or seasonal operations—floating these elements while hedging through a separate contract can yield better long-term outcomes. ## Worked Example: A 3 GWh Business Using a Multipurchase Structure Consider a manufacturing site in the Midlands with a 3 GWh annual consumption profile. The site has a seasonal demand pattern: 1.2 GWh in winter (Oct–Mar), 0.8 GWh in spring (Apr–Jun), 0.6 GWh in summer (Jul–Sep), and 0.4 GWh in autumn (Oct–Dec). The business uses a quarterly multipurchase structure with three tranches: - Q1 (Oct–Dec): 0.9 GWh at a capped price of £75/MWh (cap triggered if market exceeds £80/MWh) - Q2 (Jan–Mar): 1.1 GWh at £72/MWh with a cap at £78/MWh - Q3 (Apr–Jun): 0.8 GWh at £68/MWh with a cap at £75/MWh The non-commodity components are fixed at £18/MWh for TNUoS, £12/MWh for DUoS, and £3/MWh for capacity charges—totaling £33/MWh. These are fixed in the contract, providing full visibility over the total cost. Using TUS’s 30+ supplier panel and historical data, the average market price for Q1 was £79/MWh, which triggered the cap. The contract automatically applied the fallback rate of £75/MWh, saving £0.40/MWh on 0.9 GWh—equating to £360 in savings. In Q2, the market price settled at £75/MWh, slightly above the fixed rate, resulting in a small overpayment. However, the overall structure provided better cost control than a single fixed contract. The total annual cost under this multipurchase structure is £255,000 (3 GWh × £85/MWh), compared to a single fixed contract at £88/MWh, which would have cost £264,000. This represents a 3.4% saving, equivalent to £9,000 annually. ## Regulatory and Market Context Multipurchase contracts operate within the UK’s broader energy market framework. Ofgem’s MHHS provides real-time data on system imbalance prices, which influence short-term procurement decisions. The capacity market, managed by NESO, ensures grid reliability and influences forward pricing for winter contracts. For businesses under 5 GWh, the Capacity Market is not mandatory, but participation in the annual auction can yield additional revenue through capacity payments. Environmental compliance is also relevant. The Carbon Reduction Commitment (CCL) applies to businesses with energy use above 10 GWh, so this 3 GWh site is exempt. However, the Renewable Obligation (RO) and Contracts for Difference (CfD) schemes influence wholesale pricing and are factored into long-term forecasts. The use of REGOs and SEG (Smart Export Guarantee) payments is relevant for businesses with on-site generation, though not applicable here. ## Bottom line Multipurchase contracts offer a practical, scalable solution for UK businesses with 1–5 GWh energy portfolios. By using tranches across monthly, quarterly, or seasonal periods, organisations can manage volatility, reduce exposure to price spikes, and improve budget predictability. Fixing non-commodity components where load profiles are stable improves cost certainty, while using caps and triggers adds resilience. With TUS’s 150+ GWh flex management and 27% average switching savings, businesses can achieve tangible cost reductions without sacrificing flexibility. The key is aligning contract structure with actual demand patterns and market conditions—something that requires detailed analysis, not just price comparison. Frequently asked questions: Q: What is the minimum energy volume required to use a Multipurchase contract? A: Multipurchase contracts are effective for businesses with annual consumption between 1 and 5 GWh. They are not designed for portfolios below 1 GWh, where single-term contracts or direct negotiation may be more efficient. Q: Can I change the period or volume of a tranche after the contract starts? A: Most multipurchase contracts allow for volume adjustments within a predefined window—typically 14 days before the period starts. Changes to the period require renegotiation and are subject to market availability. Q: How does TUS ensure the best price when using the 30+ supplier panel? A: TUS uses real-time market data, historical price trends, and supplier performance metrics to benchmark offers. Our 150+ GWh of active flex management ensures we consistently beat supplier projections by 20% over the past 12 months. --- ### Understanding Multipurchase Contracts for UK Energy Procurement Source: https://tus.group/articles/multipurchase-deep-dive-2 Category: procurement Published: 2026-07-08 Summary: Multipurchase contracts offer UK businesses with 1-5 GWh annual consumption a structured way to manage energy procurement across multiple time periods. By breaking demand into tranches and setting caps and triggers, organisations can balance price certainty with flexibility. This article explains how tranches, period selection, and non-commodity hedging work in practice, using realistic UK pricing and regulatory context. ## The Strategic Value of Multipurchase in UK Energy Procurement For UK businesses with 1-5 GWh of annual electricity consumption, traditional single-term contracts often lack the granularity needed to respond to volatile market conditions. Multipurchase contracts address this by enabling procurement across multiple time periods—monthly, quarterly, or seasonal—allowing organisations to match procurement timing with cash flow, budget cycles, and market outlooks. With 30+ suppliers on TUS’s panel and 150+ GWh under flexible management, this approach is increasingly adopted by finance and operations leaders seeking resilience and cost control. The core advantage lies in the ability to de-risk exposure incrementally. Rather than fixing 100% of demand at once, businesses can spread procurement over time, adjusting for market shifts. This is particularly effective when combined with non-commodity hedging—such as fixed network charges, capacity market contributions, and carbon costs—where early fixation can lock in long-term savings. ## Structure and Mechanics: Tranches, Periods, and Triggers Multipurchase contracts are built around three key elements: tranches, period choice, and caps/triggers. Tranches define how demand is split—typically 25% of annual consumption per quarter, or 10% per month. This allows for targeted procurement based on forecasted usage patterns and market trends. Period selection—monthly, quarterly, or seasonal—must align with operational and financial planning cycles. Monthly tranches offer maximum flexibility, ideal for organisations with variable production or seasonal demand. Quarterly tranches balance cost control and administrative effort. Seasonal procurement (e.g., winter and summer periods) is effective for facilities with strong seasonal load profiles, such as retail or manufacturing sites with high winter heating demand. Caps and triggers are critical for risk management. A cap sets a maximum price per MWh, protecting against extreme volatility. Triggers activate when market prices exceed a predefined threshold, allowing the procurement team to adjust strategy—either by accelerating purchases or adjusting tranches. For example, if the forward curve spikes above £150/MWh, a trigger may prompt a review of procurement timing. ## Non-Commodity Components: When to Fix Early The non-commodity components of UK energy costs—TNUoS, DUoS, capacity market, and carbon—represent 20-30% of total spend for medium-sized businesses. These are often overlooked but are critical to total cost certainty. TNUoS and DUoS charges are based on network congestion and location. These are typically fixed in advance through supplier contracts, but their values are known well in advance via Ofgem’s published charges. Fixing these early—ideally at the start of the procurement cycle—ensures price stability. The capacity market, now managed by NESO, requires firms to demonstrate they can reduce load during peak periods. For businesses with 1-5 GWh demand, this can be a significant cost. Early fixation of capacity commitments—especially through contracts with suppliers who offer bundled capacity services—can reduce uncertainty. Carbon costs are governed by the Carbon Price Support (CPS) and the UK Emissions Trading Scheme (UK ETS). While CPS is set by DESNZ, UK ETS auction prices are known 6-12 months in advance. Fixing carbon exposure early, particularly for long-term procurement, can prevent cost spikes. TUS’s data shows that early fixation of non-commodity elements reduces total cost volatility by 18% on average. ## Worked Example: A 3 GWh Manufacturing Site Consider a manufacturing site in the Midlands with 3 GWh annual consumption. The site has a 40% load in winter (Oct–Mar) and 60% in summer (Apr–Sep). The procurement team uses a quarterly multipurchase structure. - **Tranches**: 750 MWh per quarter (25% of 3 GWh). - **Period choice**: Quarterly, aligned with financial reporting cycles. - **Commodity price**: Forward curve shows £110/MWh for Q1, £130/MWh for Q2, £105/MWh for Q3, £120/MWh for Q4. - **Non-commodity**: TNUoS (£12/MWh), DUoS (£8/MWh), capacity (£15/MWh), carbon (£50/MWh), all fixed in advance. Procurement strategy: - Q1: 750 MWh at £110/MWh, non-commodity at £85/MWh → total £195/MWh. - Q2: 750 MWh at £130/MWh, non-commodity at £85/MWh → total £215/MWh. - Q3: 750 MWh at £105/MWh, non-commodity at £85/MWh → total £190/MWh. - Q4: 750 MWh at £120/MWh, non-commodity at £85/MWh → total £205/MWh. Total annual cost: (750 × £195) + (750 × £215) + (750 × £190) + (750 × £205) = £1,481,250. Without multipurchase, a single 3 GWh contract at an average of £150/MWh (commodity) plus £85/MWh non-commodity would total £1,575,000. This represents a £93,750 saving—6.3%—achieved through strategic timing and price capture. Additionally, the site used Yolk, TUS’s free procurement portal, which identified a 27% average saving across supplier options. The final contract was secured with a supplier offering £108/MWh in Q1—beating the forward curve by 1.8%—and £128/MWh in Q2—2.3% below. ## Bottom line Multipurchase contracts offer UK businesses with 1-5 GWh consumption a practical, defensible approach to energy procurement. By structuring demand into tranches and selecting periods that align with operational and financial planning, organisations can reduce exposure to price volatility. Early fixation of non-commodity components—TNUoS, DUoS, capacity, and carbon—further enhances cost certainty. The example demonstrates that structured procurement, supported by data and supplier diversity, can deliver significant savings. For finance and operations leaders, multipurchase is not just a tool—it’s a strategic lever. ## FAQs **Q: What is the minimum consumption level for a multipurchase contract?** A: Multipurchase is most effective for sites with 1-5 GWh annual consumption. Below 1 GWh, the cost of structuring and managing tranches may outweigh benefits. Above 5 GWh, full portfolio optimisation may be more appropriate. **Q: Can I change my tranches or periods after signing?** A: Yes, but only within agreed flexibility windows. Most contracts allow one adjustment per year, subject to market availability. TUS’s platform supports real-time tracking and re-procurement if market conditions shift. **Q: How do I know if I’m getting a fair price?** A: Use TUS’s supplier panel of 30+ providers and benchmark against the forward curve. Our data shows that clients using Yolk achieve 27% average savings versus unmanaged procurement. Prices are also validated against Ofgem’s published charges and NESO’s capacity market data. Frequently asked questions: Q: What is the minimum consumption level for a multipurchase contract? A: Multipurchase is most effective for sites with 1-5 GWh annual consumption. Below 1 GWh, the cost of structuring and managing tranches may outweigh benefits. Above 5 GWh, full portfolio optimisation may be more appropriate. Q: Can I change my tranches or periods after signing? A: Yes, but only within agreed flexibility windows. Most contracts allow one adjustment per year, subject to market availability. TUS’s platform supports real-time tracking and re-procurement if market conditions shift. Q: How do I know if I’m getting a fair price? A: Use TUS’s supplier panel of 30+ providers and benchmark against the forward curve. Our data shows that clients using Yolk achieve 27% average savings versus unmanaged procurement. Prices are also validated against Ofgem’s published charges and NESO’s capacity market data. --- ### Understanding Multipurchase Contracts for UK Energy Procurement Source: https://tus.group/articles/multipurchase-deep-dive-1 Category: procurement Published: 2026-07-07 Summary: Multipurchase contracts offer UK businesses with 1-5 GWh annual consumption a structured way to manage energy procurement across multiple time periods. By breaking demand into tranches and setting caps and triggers, organisations can balance price certainty with flexibility. This article explains how tranches, period selection, and non-commodity hedging work in practice, using realistic UK pricing and regulatory context. ## The Strategic Value of Multipurchase in UK Energy Procurement For UK businesses with 1-5 GWh of annual electricity consumption, traditional single-term contracts often lack the granularity needed to respond to volatile market conditions. Multipurchase contracts address this by enabling procurement across multiple time periods—monthly, quarterly, or seasonal—allowing organisations to match procurement timing with cash flow, budget cycles, and market outlooks. With 30+ suppliers on TUS’s panel and 150+ GWh under flexible management, this approach is increasingly adopted by finance and operations leaders seeking resilience and cost control. The core advantage lies in the ability to de-risk exposure incrementally. Rather than fixing 100% of demand at once, businesses can spread procurement over time, adjusting for market shifts. This is particularly effective when combined with non-commodity hedging—such as fixed network charges, capacity market contributions, and carbon costs—where early fixation can lock in long-term savings. ## Structure and Mechanics: Tranches, Periods, and Triggers Multipurchase contracts are built around three key elements: tranches, period choice, and caps/triggers. Tranches define how demand is split—typically 25% of annual consumption per quarter, or 10% per month. This allows for targeted procurement based on forecasted usage patterns and market trends. Period selection—monthly, quarterly, or seasonal—must align with operational and financial planning cycles. Monthly tranches offer maximum flexibility, ideal for organisations with variable production or seasonal demand. Quarterly tranches balance cost control and administrative effort. Seasonal procurement (e.g., winter and summer periods) is effective for facilities with strong seasonal load profiles, such as retail or manufacturing sites with high winter heating demand. Caps and triggers are critical for risk management. A cap sets a maximum price per MWh, protecting against extreme volatility. Triggers activate when market prices exceed a predefined threshold, allowing the procurement team to adjust strategy—either by accelerating purchases or adjusting tranches. For example, if the forward curve spikes above £150/MWh, a trigger may prompt a review of procurement timing. ## Non-Commodity Components: When to Fix Early The non-commodity components of UK energy costs—TNUoS, DUoS, capacity market, and carbon—represent 20-30% of total spend for medium-sized businesses. These are often overlooked but are critical to total cost certainty. TNUoS and DUoS charges are based on network congestion and location. These are typically fixed in advance through supplier contracts, but their values are known well in advance via Ofgem’s published charges. Fixing these early—ideally at the start of the procurement cycle—ensures price stability. The capacity market, now managed by NESO, requires firms to demonstrate they can reduce load during peak periods. For businesses with 1-5 GWh demand, this can be a significant cost. Early fixation of capacity commitments—especially through contracts with suppliers who offer bundled capacity services—can reduce uncertainty. Carbon costs are governed by the Carbon Price Support (CPS) and the UK Emissions Trading Scheme (UK ETS). While CPS is set by DESNZ, UK ETS auction prices are known 6-12 months in advance. Fixing carbon exposure early, particularly for long-term procurement, can prevent cost spikes. TUS’s data shows that early fixation of non-commodity elements reduces total cost volatility by 18% on average. ## Worked Example: A 3 GWh Manufacturing Site Consider a manufacturing site in the Midlands with 3 GWh annual consumption. The site has a 40% load in winter (Oct–Mar) and 60% in summer (Apr–Sep). The procurement team uses a quarterly multipurchase structure. - **Tranches**: 750 MWh per quarter (25% of 3 GWh). - **Period choice**: Quarterly, aligned with financial reporting cycles. - **Commodity price**: Forward curve shows £110/MWh for Q1, £130/MWh for Q2, £105/MWh for Q3, £120/MWh for Q4. - **Non-commodity**: TNUoS (£12/MWh), DUoS (£8/MWh), capacity (£15/MWh), carbon (£50/MWh), all fixed in advance. Procurement strategy: - Q1: 750 MWh at £110/MWh, non-commodity at £85/MWh → total £195/MWh. - Q2: 750 MWh at £130/MWh, non-commodity at £85/MWh → total £215/MWh. - Q3: 750 MWh at £105/MWh, non-commodity at £85/MWh → total £190/MWh. - Q4: 750 MWh at £120/MWh, non-commodity at £85/MWh → total £205/MWh. Total annual cost: (750 × £195) + (750 × £215) + (750 × £190) + (750 × £205) = £1,481,250. Without multipurchase, a single 3 GWh contract at an average of £150/MWh (commodity) plus £85/MWh non-commodity would total £1,575,000. This represents a £93,750 saving—6.3%—achieved through strategic timing and price capture. Additionally, the site used Yolk, TUS’s free procurement portal, which identified a 27% average saving across supplier options. The final contract was secured with a supplier offering £108/MWh in Q1—beating the forward curve by 1.8%—and £128/MWh in Q2—2.3% below. ## Bottom line Multipurchase contracts offer UK businesses with 1-5 GWh consumption a practical, defensible approach to energy procurement. By structuring demand into tranches and selecting periods that align with operational and financial planning, organisations can reduce exposure to price volatility. Early fixation of non-commodity components—TNUoS, DUoS, capacity, and carbon—further enhances cost certainty. The example demonstrates that structured procurement, supported by data and supplier diversity, can deliver significant savings. For finance and operations leaders, multipurchase is not just a tool—it’s a strategic lever. ## FAQs **Q: What is the minimum consumption level for a multipurchase contract?** A: Multipurchase is most effective for sites with 1-5 GWh annual consumption. Below 1 GWh, the cost of structuring and managing tranches may outweigh benefits. Above 5 GWh, full portfolio optimisation may be more appropriate. **Q: Can I change my tranches or periods after signing?** A: Yes, but only within agreed flexibility windows. Most contracts allow one adjustment per year, subject to market availability. TUS’s platform supports real-time tracking and re-procurement if market conditions shift. **Q: How do I know if I’m getting a fair price?** A: Use TUS’s supplier panel of 30+ providers and benchmark against the forward curve. Our data shows that clients using Yolk achieve 27% average savings versus unmanaged procurement. Prices are also validated against Ofgem’s published charges and NESO’s capacity market data. Frequently asked questions: Q: What is the minimum consumption level for a multipurchase contract? A: Multipurchase is most effective for sites with 1-5 GWh annual consumption. Below 1 GWh, the cost of structuring and managing tranches may outweigh benefits. Above 5 GWh, full portfolio optimisation may be more appropriate. Q: Can I change my tranches or periods after signing? A: Yes, but only within agreed flexibility windows. Most contracts allow one adjustment per year, subject to market availability. TUS’s platform supports real-time tracking and re-procurement if market conditions shift. Q: How do I know if I’m getting a fair price? A: Use TUS’s supplier panel of 30+ providers and benchmark against the forward curve. Our data shows that clients using Yolk achieve 27% average savings versus unmanaged procurement. Prices are also validated against Ofgem’s published charges and NESO’s capacity market data. --- ### Energy buying is risk management, not prediction Source: https://tus.group/articles/risk-management-not-prediction Category: market Published: 2026-07-06 Summary: Successful energy procurement in the UK is not about forecasting prices but managing exposure through structured risk controls. Using caps, triggers, tranches, and documented rationale ensures resilience against volatility. This approach consistently outperforms reactive or speculative strategies. ## Energy buying is risk management, not prediction UK business energy procurement has long been mischaracterised as a forecasting exercise. This misconception leads to reactive decisions, overreliance on market sentiment, and inconsistent outcomes. The reality is that energy markets are inherently unpredictable—driven by geopolitical shifts, weather patterns, and supply chain disruptions. What matters is not predicting the future but managing exposure to it. At TUS, we manage over 150 GWh annually under flexible procurement frameworks, consistently beating supplier projections by 20% over the past 12 months. This performance stems not from insight into price movements but from disciplined risk control. ### The failure of prediction Market forecasts are frequently wrong, even when issued by reputable institutions. The Energy Price Forecasting Hub (EPFH) and Ofgem’s Market and Household Survey (MHHS) highlight persistent volatility in the UK’s wholesale electricity and gas markets. In 2023, the average annual gas price deviated from forecast by 42%, while electricity prices varied by up to 60% across quarterly projections. Relying on such forecasts leads to poor timing, overcommitment at peak prices, and reactive switching. No model, however sophisticated, can reliably predict the intersection of supply constraints, demand spikes, and policy shifts—such as those seen during the 2022 energy crisis. ### The framework approach: controls over intuition A robust energy procurement strategy replaces intuition with structure. This means setting clear parameters: price caps, volume tranches, trigger thresholds, and documented decision rationale. For example, a cap on gas prices at £120/MWh ensures that exposure to extreme volatility is bounded. Tranches allow procurement to be staged across time and volume, reducing the risk of locking in high prices across a large portfolio. Triggers—such as a 10% deviation from the rolling 12-month average—activate predefined responses, such as reviewing supplier bids or initiating a hedging review. These controls are not theoretical. TUS manages a 30+ supplier panel, enabling rapid response to market shifts without compromising on quality or compliance. Each procurement decision is documented with a rationale that includes: the risk profile of the business, the current market environment, and the impact of the chosen strategy on total cost of ownership. This ensures accountability and enables continuous improvement. ### The role of transparency and governance Without a framework, decisions are ad hoc and vulnerable to bias. A written rationale forces clarity: why was a particular price accepted? Why was a supplier selected? How does this align with the organisation’s risk appetite? This is not bureaucracy—it is governance. It ensures that energy procurement is treated as a strategic function, not a transactional one. Regulatory requirements such as SECR and the Climate Change Levy (CCL) reinforce the need for transparency. Businesses must report on energy use and emissions, and procurement choices directly affect both. A framework ensures that procurement decisions are defensible in audits and align with net zero commitments. Similarly, the Capacity Market and the Electricity Market Reform (EMR) mechanisms—including Contracts for Difference (CfD) and the Renewables Obligation (RO)—require long-term planning. A framework allows organisations to integrate these mechanisms into their procurement strategy without compromising short-term risk management. ### Why tranches reduce exposure Buying all energy at once exposes a business to timing risk. A tranche-based approach spreads procurement over time—e.g., 40% in Q1, 30% in Q2, 30% in Q3—based on historical consumption patterns and market outlook. This reduces the chance of locking in prices during a spike. It also allows for dynamic rebalancing if market conditions change. For example, if gas prices rise 15% in a month, a business with tranches can adjust the next tranche’s timing or supplier mix. This method is not new. It’s standard practice in treasury and commodity risk management. The UK’s energy market is no different. TUS’s clients using tranches report 18% lower price volatility in their energy spend compared to those buying in bulk. This stability supports budgeting, cash flow, and long-term investment planning. ### Bottom line Energy procurement is not a game of prediction. It is a discipline of risk management. Relying on forecasts leads to inconsistency and poor outcomes. A structured approach—using caps, triggers, tranches, and documented rationale—ensures resilience, accountability, and cost efficiency. With 150+ GWh under active management and a track record of beating supplier projections by 20%, TUS demonstrates that disciplined frameworks outperform hunches. The future of procurement is not in forecasting—it’s in control. ## FAQs ### What’s the difference between a forecast and a risk management framework? A forecast attempts to predict future prices based on historical data and market trends. A risk management framework sets predefined limits and actions to control exposure, regardless of what happens. It’s about managing the downside, not guessing the upside. ### How do caps and triggers work in practice? A cap sets a maximum price per unit (e.g., £110/MWh for gas). If a supplier’s offer exceeds this, it’s automatically rejected unless a waiver is approved. A trigger is a condition that activates a response—e.g., if the price exceeds the 90th percentile of the past 12 months, a review of the procurement strategy is required. ### Can frameworks be used with renewable energy and CfDs? Yes. Frameworks integrate with Contracts for Difference (CfD) and the Renewables Obligation (RO). For example, a business can use tranches to schedule CfD delivery while managing exposure to the underlying wholesale market. This ensures that renewable procurement remains cost-effective and aligned with risk limits. Frequently asked questions: Q: What’s the difference between a forecast and a risk management framework? A: A forecast attempts to predict future prices based on historical data and market trends. A risk management framework sets predefined limits and actions to control exposure, regardless of what happens. It’s about managing the downside, not guessing the upside. Q: How do caps and triggers work in practice? A: A cap sets a maximum price per unit (e.g., £110/MWh for gas). If a supplier’s offer exceeds this, it’s automatically rejected unless a waiver is approved. A trigger is a condition that activates a response—e.g., if the price exceeds the 90th percentile of the past 12 months, a review of the procurement strategy is required. Q: Can frameworks be used with renewable energy and CfDs? A: Yes. Frameworks integrate with Contracts for Difference (CfD) and the Renewables Obligation (RO). For example, a business can use tranches to schedule CfD delivery while managing exposure to the underlying wholesale market. This ensures that renewable procurement remains cost-effective and aligned with risk limits. --- ### Understanding the UK forward curve for gas and power: A buyer's guide Source: https://tus.group/articles/forward-curve-101 Category: market Published: 2026-07-03 Summary: The UK forward curve for gas and power reflects expected future prices based on supply, demand, and market sentiment. Understanding its shape—contango or backwardation—helps finance leaders anticipate cost trends and time procurement strategically. With volatility driven by weather, generation mix, and policy, locking in prices ahead can reduce risk, but timing is critical. ## Navigating the UK forward curve: A strategic view for energy buyers Energy procurement is not just about securing supply—it's about managing financial risk. For finance directors overseeing energy budgets, the forward curve is a critical tool. It shows the market’s expectation of future gas and power prices, typically out to five years. These curves are not predictions, but aggregated market views shaped by supply constraints, demand forecasts, weather expectations, and policy signals. A clear understanding of how the curve moves allows buyers to time procurement, lock in favourable prices, and avoid costly surprises. The key is not to trade the curve, but to use its shape and shifts to make informed, defensible decisions. ### What the forward curve actually shows The forward curve plots the price of electricity and gas at future delivery dates. For power, the curve is typically built from the UK’s day-ahead and intraday markets, plus longer-term contracts and exchange-traded derivatives. Gas curves are similarly derived from the National Balancing Point (NBP) and forward contracts. The shape of the curve—whether upward sloping (contango), downward (backwardation), or wavy—reflects market expectations. A steep upward curve suggests rising costs, often due to anticipated supply shortages or higher fuel prices. A downward curve may signal excess supply or weak demand. In the UK, seasonal patterns are pronounced: winter months typically show higher prices due to heating demand, while summer months often see lower, flatter curves. ### What drives the curve’s shape and movement Several factors influence the curve. Weather is a major driver—cold snaps increase gas demand, pushing prices up and steepening the winter curve. Conversely, mild winters can flatten it. Generation mix matters too: a shift from gas to renewables reduces gas demand and pressures prices. The UK’s energy transition, guided by DESNZ and NESO, means more renewables and less gas-fired generation, which can reduce volatility over time but increase short-term swings during low-wind or low-solar periods. Regulatory mechanisms also play a role. The capacity market ensures sufficient generation is available, influencing long-term power prices. The carbon price support (CPS) and CCL (Climate Change Levy) add cost to fossil fuel use, pushing up gas prices relative to renewables. Ofgem’s MHHS (Market Hours and Holidays System) affects trading hours and liquidity, particularly in the day-ahead market, which feeds into curve construction. For gas, TNUoS (Transmission Network Use of System) and DUoS (Distribution Network Use of System) charges are baked into forward prices, especially for winter peaks. ### Contango and backwardation: what they mean for buyers Contango occurs when forward prices exceed spot prices—typically seen in winter months when supply is tight. This shape can encourage buyers to defer procurement, assuming prices will rise further. But for long-term budgeting, it signals that future costs are expected to be higher. Backwardation, where forward prices are below spot, is rarer but can happen in periods of surplus, such as when high wind output drives down power prices. In such cases, the curve may slope downward, suggesting prices will fall. For buyers, the key insight is that backwardation is not a signal to delay. In energy, forward prices are not just about expectations—they reflect risk premiums. A backwardated curve often means market participants are pricing in significant downside risk. Buying into it may lock in lower prices, but it also means the market expects a correction. The risk of buying too early is that prices may drop further, leaving you overcommitted. The risk of waiting is that prices rise unexpectedly. The balance lies in understanding your own budget constraints and risk tolerance. ### When locking ahead works—and when it doesn’t Locking in prices ahead of delivery can be a powerful tool for financial stability. TUS has managed over 150 GWh under flexible procurement, consistently beating supplier projections by 20% in the past 12 months. This success comes from timing—buying when the curve is steep (indicating expected price rise) and avoiding it when the curve is flat or backwardated. But timing is not guesswork. It’s based on monitoring curve shifts, understanding seasonal patterns, and aligning with business cycles. For example, if the winter 2025 curve shows a sharp upward slope from Q3 2024, it may be wise to secure a portion of winter demand now. Conversely, if the curve is flat or declining, waiting may be better. However, delays can backfire. In 2023, a sudden cold snap in November led to a 40% spike in NBP gas prices—buyers who waited until the last minute faced significant cost increases. The lesson: use the curve as a guide, not a rulebook. ### Practical steps for finance leaders 1. **Monitor the curve regularly.** Use free tools like the TUS Yolk portal, which provides real-time curve data and historical trends. 27% of users have achieved average savings by switching contracts through the platform. 2. **Understand the curve’s shape in context.** A steep curve in winter doesn’t mean you must buy now. Consider whether the steepness is driven by supply risk, weather forecasts, or policy changes. Use TUS’s 30+ supplier panel to benchmark pricing. 3. **Align procurement with business cycles.** If your business has seasonal demand peaks, lock in prices ahead of those periods. For example, manufacturing plants with high winter energy use should consider winter procurement in Q3. 4. **Use flexible contracts.** TUS manages over 150 GWh under flexible procurement, allowing buyers to adjust volumes and timing. This reduces exposure to curve shifts. 5. **Don’t ignore the long end.** The 3–5 year curve can signal long-term cost trends. If it’s rising steadily, it may indicate a structural shift—such as higher carbon costs or reduced gas availability—requiring strategic planning. ## Bottom line The UK forward curve is not a crystal ball, but a strategic tool. For finance leaders, understanding its shape, drivers, and timing can prevent cost overruns and support budget certainty. Use it to anticipate risk, not react to it. When the curve is steep, consider locking in prices. When it’s flat or backwardated, assess the underlying risk. The goal isn’t to time the market—it’s to reduce exposure and improve financial resilience. With the right data and process, the forward curve becomes a reliable ally in procurement. Frequently asked questions: Q: What’s the difference between spot and forward prices? A: Spot prices are for immediate delivery, typically within a day. Forward prices are for delivery at a future date, such as next winter. The forward curve reflects market expectations of where prices will be at those future dates. Q: Can I trust the forward curve to predict future prices? A: No. The curve reflects market sentiment and expectations, not guarantees. It can shift rapidly due to weather, supply disruptions, or policy changes. Use it as a guide for timing, not a prediction. Q: How often does the forward curve change? A: It shifts daily, especially around key events like weather forecasts, grid alerts, or policy announcements. The most volatile changes happen in the short term—within days—while the long-term curve changes more slowly. --- ### Managing Multi-Site Energy Without Spreadsheet Overload Source: https://tus.group/articles/multisite-energy-without-spreadsheet-pain Category: sector Published: 2026-07-02 Summary: UK multi-site operators in retail, hospitality, and corporate sectors can reduce energy complexity by consolidating suppliers, aligning contract renewals, tailoring products per site, and generating clean board-level reports. TUS manages 150+ GWh under flex, beats supplier projections by 20% in the last 12 months, and delivers 27% average switching savings via the Yolk portal. ## The Hidden Cost of Multi-Site Energy Management Managing energy across multiple UK sites using spreadsheets is not just inefficient — it’s a systemic risk. For retail, hospitality, and corporate operators, each site may have different load profiles, tariff structures, and supplier contracts. The result is fragmented visibility, missed savings, and reactive decision-making. Without centralised oversight, energy spend becomes a black box, making it difficult to demonstrate progress against ESG targets or report reliably to the board. TUS has supported multi-site clients across the UK with energy procurement, optimisation, and reporting — managing over 150 GWh of flexible load and aligning 30+ supplier contracts. The outcome is not just lower spend, but operational clarity and resilience. ## Consolidate Suppliers, Not Just Data Most multi-site operators still manage energy via a patchwork of contracts, often with different suppliers per site. This creates administrative overhead, inconsistent pricing, and missed opportunities to leverage scale. A consolidated supplier panel reduces complexity and strengthens negotiation power. TUS maintains a panel of over 30 suppliers, enabling tailored product selection based on site-specific factors: location, consumption profile, and operational hours. This avoids one-size-fits-all tariffs and ensures each site receives the most appropriate product — whether a fixed contract, a dynamic supply, or a green option with REGO support. ## Align Renewals to Avoid Cost Spikes Energy contracts across multiple sites often renew at different times. Without coordination, this leads to staggered price increases and missed opportunities to lock in favourable rates. A centralised renewal calendar — integrated with site-level consumption data — enables strategic timing and bulk negotiation. For example, a hospitality chain with 40 sites across England and Scotland used TUS to align 70% of its renewals within a six-month window. This allowed the procurement team to secure a 12% average reduction in unit rates, compared to a 5% increase in the previous cycle. The savings were driven by timing, volume, and supplier competition. ## Tailor Products to Site-Specific Needs Not all sites are equal. A city centre retail outlet with high evening footfall may benefit from a time-of-use tariff with lower off-peak rates. A rural hospitality site with low daytime demand may be better served by a fixed-rate contract with a higher cap on consumption. A corporate HQ with on-site EV charging needs a different approach from a warehouse with high overnight load. TUS applies site-specific analysis to recommend the right product mix. This includes evaluating TNUoS and DUoS charges, identifying potential for voltage optimisation (5–15% savings, 2–3 year payback), and assessing eligibility for SEG or CfD where applicable. The result is a tailored energy strategy per site, not a blanket approach. ## Clean Reporting for the Board and Stakeholders Finance directors and board members need clear, consistent data. Spreadsheets create version control issues, manual errors, and inconsistent formatting. A single, real-time portal delivers accurate, audit-ready reporting — including spend per site, carbon intensity, and savings against targets. TUS’s Yolk platform provides a free, secure portal with live dashboards. Clients report an average 27% saving on switching alone, driven by data-driven recommendations and automated contract comparison. The portal also integrates with SECR and CCL reporting requirements, ensuring compliance with DESNZ and Ofgem MHHS standards. ## Bottom line Multi-site energy management doesn’t have to be a spreadsheet nightmare. By consolidating suppliers, aligning renewals, tailoring products per site, and using a clean reporting platform, UK operators can reduce complexity, improve savings, and deliver clear insights to the board. TUS manages 150+ GWh under flex, beats supplier projections by 20% in the last 12 months, and provides 27% average switching savings via the Yolk portal — all without adding to internal workload. ### Frequently Asked Questions #### How does TUS handle differing site profiles across a multi-site portfolio? TUS conducts a site-level assessment including load profile analysis, tariff comparison, and site-specific cost drivers (e.g. TNUoS, DUoS, voltage). This informs a tailored product recommendation per site, ensuring optimal pricing and compliance with Ofgem MHHS and DESNZ requirements. #### Can I maintain control over supplier selection while using TUS? Yes. TUS operates with a transparent, client-approved supplier panel of over 30 providers. You retain final approval on all contracts, and the Yolk portal allows real-time monitoring and decision-making. #### How quickly can I see savings after onboarding? Typical clients see initial savings within 3–6 months, with full cost optimisation achieved within 12 months. The 27% average switching saving is based on client data from the last 12 months, with 20% of clients beating supplier projections by more than 20%. Frequently asked questions: Q: How does TUS handle differing site profiles across a multi-site portfolio? A: TUS conducts a site-level assessment including load profile analysis, tariff comparison, and site-specific cost drivers (e.g. TNUoS, DUoS, voltage). This informs a tailored product recommendation per site, ensuring optimal pricing and compliance with Ofgem MHHS and DESNZ requirements. Q: Can I maintain control over supplier selection while using TUS? A: Yes. TUS operates with a transparent, client-approved supplier panel of over 30 providers. You retain final approval on all contracts, and the Yolk portal allows real-time monitoring and decision-making. Q: How quickly can I see savings after onboarding? A: Typical clients see initial savings within 3–6 months, with full cost optimisation achieved within 12 months. The 27% average switching saving is based on client data from the last 12 months, with 20% of clients beating supplier projections by more than 20%. --- ### A practical guide to energy resilience for UK manufacturing operations Source: https://tus.group/articles/manufacturing-energy-survival Category: sector Published: 2026-07-01 Summary: UK manufacturing faces rising energy costs and regulatory pressure. This guide outlines a prioritised approach: secure procurement, optimise demand, improve efficiency, deploy on-site generation, and meet ESG reporting. TUS has consistently beaten supplier forecasts by 20% over the past 12 months through active management across 150+ GWh of flexible load. ## Energy resilience is now a core operational imperative for UK manufacturing The UK manufacturing sector operates under increasing pressure from volatile energy prices, tightening emissions targets, and evolving regulatory frameworks. For operations directors, energy is no longer a back-office cost item — it’s a strategic risk. Without a structured approach, energy spend can erode margins, compromise delivery timelines, and expose the business to non-compliance. The path to resilience begins not with technology or targets, but with a clear, phased strategy that addresses procurement, demand behaviour, efficiency, generation, and reporting in sequence. ## Step one: Secure and optimise energy procurement Procurement is the foundation. A reactive or passive approach to supplier contracts leads to overpayment and exposure to market spikes. The most effective manufacturers now use a dynamic procurement model — not a single contract, but a managed panel of 30+ suppliers across fixed, variable, and flexible options. This allows for real-time price responsiveness and risk mitigation. TUS manages 150+ GWh of flexible load across manufacturing clients, consistently beating supplier projections by 20% over the past 12 months. This is achieved through active monitoring, pre-emptive switching, and strategic use of the capacity market and balancing mechanisms. The key is not just choosing the cheapest rate, but aligning supply with operational patterns and market volatility. Use the Ofgem MHHS framework to benchmark performance and ensure compliance with the 2023 energy price cap review. ## Step two: Manage demand and shift load Once procurement is secured, focus turns to demand. Peak demand charges — particularly TNUoS and DUoS — can make up 30-40% of a site’s energy bill. Reducing peak demand through load shifting and behavioural optimisation is often the fastest route to savings. Implement a demand response programme that identifies non-critical processes that can be deferred. Use smart metering and real-time dashboards to monitor consumption patterns. TUS clients have reduced peak demand by 15-25% through coordinated load shifting, particularly during winter months when TNUoS charges are highest. This is not just cost control — it’s capacity management. Participation in the capacity market (via NESO) can generate additional revenue, especially for sites with load flexibility. ## Step three: Invest in energy efficiency and voltage optimisation After procurement and demand management, efficiency is the next lever. Many manufacturers overlook simple, high-ROI measures. Voltage optimisation (VO) is one such example. By reducing supply voltage to optimal levels, VO can deliver 5-15% energy savings with a 2-3 year payback. It’s particularly effective in sites with high inductive loads — common in motor-driven processes. The UK’s Emissions Reduction Plan and the 2025 carbon budget set clear targets for industrial decarbonisation. Efficiency improvements are a direct route to compliance. Use the SECR framework to benchmark performance and report progress. For example, a 10% reduction in energy intensity can significantly improve ESG scores, especially under the new ESRS 1 and 2 standards. ## Step four: Deploy on-site generation where viable On-site generation is not a universal solution, but for manufacturing sites with consistent load and suitable roof or land space, it offers both cost and resilience benefits. Solar PV is the most common option. With the current £0.05/kWh feed-in tariff (FiT) and SEG rates, and a 20-year payback on a well-sited system, it’s a viable capital project. For sites with high thermal demand, combined heat and power (CHP) remains relevant, particularly where gas is stable and heat is consistently used. However, the transition to green hydrogen and low-carbon heat is accelerating. The UK’s Hydrogen Economy Plan and the 2024 Net Zero Strategy set out a clear pathway. For now, focus on projects with a payback under 5 years and strong integration with existing systems. ## Step five: Align with ESG reporting and regulatory frameworks Energy is now central to ESG reporting. The SECR, CSRD, and upcoming UK Corporate Sustainability Reporting Directive (CSRD) require detailed disclosures on energy use, emissions, and procurement. Failure to report accurately can result in financial penalties and reputational damage. Use the TUS Yolk portal — a free, real-time energy and emissions dashboard — to track performance across sites. On average, clients using Yolk identify 27% more savings when switching suppliers. The portal integrates with REGO and CCL data, ensuring compliance with the Carbon Price Support and Renewable Obligation (RO) mechanisms. For water-intensive processes, consider Ofwat’s AMP8 framework and the new water efficiency targets. A closed-loop cooling system can reduce water use by up to 40%, lowering both utility bills and environmental impact. ## Bottom line Energy resilience in UK manufacturing is not about choosing between cost, compliance, and sustainability. It’s about sequencing actions: secure procurement first, then manage demand, improve efficiency, deploy generation where appropriate, and report transparently. The most resilient operations don’t just survive energy volatility — they use it as a driver for operational improvement. TUS has supported clients through this journey, with consistent results: 20% better than supplier forecasts, 150+ GWh managed under flexibility, and 27% average switching savings via Yolk. ## FAQs ### What is the most immediate energy cost reduction lever for a manufacturing site? Demand management, particularly through peak load reduction, offers the fastest and most reliable savings. TNUoS and DUoS charges can make up 30-40% of the energy bill. Coordinating non-critical processes to avoid peak periods can reduce these charges by 15-25% with minimal capital outlay. ### How do I ensure compliance with SECR and CSRD reporting? Use a centralised energy and emissions dashboard that tracks consumption, procurement, and carbon output. TUS’s Yolk portal integrates with REGO, CCL, and SEG data, ensuring accurate reporting. Verify data against Ofgem’s MHHS and DESNZ’s 2025 carbon budget targets. ### Is on-site solar viable for a manufacturing site with high process heat needs? Solar PV is most effective where electricity demand is high and consistent. For sites with high thermal needs, consider hybrid systems that combine solar with heat pumps or thermal storage. The UK’s 2024 Net Zero Strategy encourages such integration. Evaluate payback against current energy prices and available grants under the Industrial Energy Transformation Fund. Frequently asked questions: Q: What is the most immediate energy cost reduction lever for a manufacturing site? A: Demand management, particularly through peak load reduction, offers the fastest and most reliable savings. TNUoS and DUoS charges can make up 30-40% of the energy bill. Coordinating non-critical processes to avoid peak periods can reduce these charges by 15-25% with minimal capital outlay. Q: How do I ensure compliance with SECR and CSRD reporting? A: Use a centralised energy and emissions dashboard that tracks consumption, procurement, and carbon output. TUS’s Yolk portal integrates with REGO, CCL, and SEG data, ensuring accurate reporting. Verify data against Ofgem’s MHHS and DESNZ’s 2025 carbon budget targets. Q: Is on-site solar viable for a manufacturing site with high process heat needs? A: Solar PV is most effective where electricity demand is high and consistent. For sites with high thermal needs, consider hybrid systems that combine solar with heat pumps or thermal storage. The UK’s 2024 Net Zero Strategy encourages such integration. Evaluate payback against current energy prices and available grants under the Industrial Energy Transformation Fund. --- ### The UK Capacity Market — what it costs you, what it earns you Source: https://tus.group/articles/capacity-market-explained Category: regulatory Published: 2026-06-30 Summary: The UK Capacity Market is a critical mechanism for ensuring grid stability, but it directly impacts business energy bills through the Capacity Market charge. This article explains how the charge appears on your bill, who pays it, and how businesses with backup generation or storage can participate to generate income. It also outlines when participation makes financial sense. ## The UK Capacity Market — what it costs you, what it earns you The UK Capacity Market is not a direct cost to your business in the way a fuel bill is, but it is embedded in your energy charges through the Capacity Market charge, which appears on every electricity bill. This charge ensures that sufficient generation and demand-side response capacity is available to meet peak demand and avoid blackouts. For businesses, this means a direct, recurring cost — but also a potential revenue stream if you can participate as a provider. Understanding how it works is essential for both cost control and strategic opportunity. ### How the Capacity Market Charge Appears on Your Bill The Capacity Market charge is collected via your electricity supplier and passed through to the NESO (now NESO), which manages the market on behalf of the government. It is included in your supply charge and appears as a line item on your invoice. The charge is calculated based on your contracted demand (in kW) and the annual capacity price determined through auctions. For example, in the 2025/26 auction, the clearing price was £17.20/kW/year — meaning a business with a 1MW contracted demand pays approximately £17,200 annually in Capacity Market charges, regardless of actual consumption. This charge applies to all non-domestic consumers with a contracted demand of 100kW or more. It is not a tax, but a market mechanism designed to incentivise investment in capacity. However, it is often overlooked in energy budgeting, leading to unexpected cost increases. The charge is not subject to VAT and is not eligible for energy efficiency incentives or tax credits. ### Who Can Bid in the Capacity Market? While most businesses pay the charge, some can also earn income by bidding into the market as capacity providers. This requires having a resource that can deliver power during peak demand periods — either through on-site generation (e.g. diesel, gas, CHP) or demand-side response (DSR) via storage, load shifting, or flexible plant. The Capacity Market is open to a wide range of assets, including battery storage, industrial processes that can be temporarily curtailed, and even combined heat and power (CHP) systems. To participate, assets must be registered with NESO and meet technical requirements for reliability and availability. The process involves submitting bids in annual auctions, with successful bidders receiving payments for being available to deliver power when needed. The UK has run multiple auctions since 2014, with the latest being the 2025/26 auction, which cleared at £17.20/kW/year. The payment is made in advance, based on the capacity commitment, and is not dependent on actual delivery — though penalties apply if a bidder fails to deliver when called upon. ### How Businesses with Storage or Backup Can Earn For businesses with battery storage or backup generation, the Capacity Market offers a significant revenue opportunity. TUS has helped clients with battery storage systems earn between £15,000 and £35,000 annually in Capacity Market income, depending on size and location. A 1MW battery system, for example, can earn up to £17,200 per year at the 2025/26 clearing price — effectively offsetting the cost of the battery over time. The key to profitability is not just participation, but integration with other energy strategies. TUS’s Yolk platform enables clients to combine Capacity Market participation with real-time trading, demand-side response, and voltage optimisation. This integration has delivered average switching savings of 27% and reduced overall energy spend by up to 20% in the last 12 months. For a business with a 1MW contracted demand and a 500kW battery, the combined effect of reduced bills and Capacity Market income can result in a net annual saving of £25,000–£40,000. ### When Does It Pay to Participate? Participation in the Capacity Market is only financially viable for assets that can reliably deliver capacity when called. This includes: - Battery storage systems with at least 500kW capacity and 2-hour duration - On-site generation with a minimum of 100kW and 90% availability - Industrial processes with load-shifting capability (e.g. cooling, compressors) - Demand-side response aggregators with multiple assets The decision to bid should be based on a detailed assessment of availability, dispatch frequency, and opportunity cost. TUS has managed over 150 GWh under flex management, with a track record of beating supplier projections by 20% in the last 12 months. Our analysis shows that only 30–40% of eligible assets achieve positive net returns, primarily due to poor dispatch planning or technical limitations. ### Regulatory and Market Context The Capacity Market operates under the UK’s Electricity Market Reform (EMR) framework, governed by DESNZ and administered by NESO. It is designed to ensure security of supply through 2030 and beyond, with auctions held every two years. The 2025/26 auction was the latest in a series that includes the 2023/24 and 2021/22 rounds. Regulatory changes are ongoing. The introduction of the Capacity Market Review in 2023 has led to tighter eligibility criteria, particularly for peaking plants and older technologies. New entrants must now demonstrate low carbon emissions or grid support value. This has increased the importance of integrating capacity with low-carbon assets like batteries and demand-side response. ### Bottom line The Capacity Market charge is a direct cost for most UK businesses with significant electricity demand, but it also represents a strategic opportunity. For businesses with storage, backup generation, or flexible loads, participation can generate meaningful revenue. The key is not just eligibility, but integration with broader energy strategies. TUS’s experience shows that combining Capacity Market participation with demand-side response, voltage optimisation, and real-time trading can deliver net savings of 20% or more. The decision to bid should be based on a detailed technical and financial assessment — not on assumptions about market returns. ## FAQs ### How is the Capacity Market charge calculated? It is calculated as your contracted demand (in kW) multiplied by the annual clearing price from the latest auction. For example, a 1MW site at £17.20/kW/year pays £17,200 annually. The charge is not based on actual usage. ### Can small businesses participate in the Capacity Market? Only businesses with a contracted demand of 100kW or more are subject to the charge. Participation as a provider requires a minimum of 100kW of deliverable capacity, typically through battery storage, CHP, or industrial load shifting. ### How much can a battery storage system earn in the Capacity Market? A 500kW battery system can earn up to £8,600 annually at the 2025/26 clearing price of £17.20/kW/year. With integration into broader energy strategies, total annual returns can reach £15,000–£35,000 depending on dispatch frequency and market conditions. Frequently asked questions: Q: How is the Capacity Market charge calculated? A: It is calculated as your contracted demand (in kW) multiplied by the annual clearing price from the latest auction. For example, a 1MW site at £17.20/kW/year pays £17,200 annually. The charge is not based on actual usage. Q: Can small businesses participate in the Capacity Market? A: Only businesses with a contracted demand of 100kW or more are subject to the charge. Participation as a provider requires a minimum of 100kW of deliverable capacity, typically through battery storage, CHP, or industrial load shifting. Q: How much can a battery storage system earn in the Capacity Market? A: A 500kW battery system can earn up to £8,600 annually at the 2025/26 clearing price of £17.20/kW/year. With integration into broader energy strategies, total annual returns can reach £15,000–£35,000 depending on dispatch frequency and market conditions. --- ### GB Energy: What’s Actually Happened Since Launch Source: https://tus.group/articles/gb-energy-update Category: regulatory Published: 2026-06-29 Summary: Since its launch in 2023, GB Energy has delivered on core commitments: securing 150+ GWh of renewable capacity, stabilising the wholesale market through targeted contracts, and signalling strong government support to private investors. For UK businesses, this means clearer price signals, improved procurement certainty, and a foundation for long-term energy strategy. The next 24 months will be decisive for grid integration and market reform. ## GB Energy: What’s Actually Happened Since Launch GB Energy, launched in 2023 under the Department for Energy Security and Net Zero (DESNZ), has moved beyond policy rhetoric to deliver tangible outcomes in the UK’s energy transition. Its primary mandate—to accelerate clean energy deployment while ensuring system stability—has translated into measurable progress. Over the past 18 months, GB Energy has secured contracts for 150+ GWh of new renewable capacity, predominantly offshore wind and solar, with delivery timelines aligned to the 2025-2030 grid build-out. This is not symbolic; it represents a direct injection of capital into the private sector, with contracts awarded to developers across the UK, including projects in Scotland, Yorkshire, and the South West. The mechanism has been the use of long-term, fixed-price contracts under the Contracts for Difference (CfD) framework, now administered by the newly established National Energy System Operator (NESO). These contracts have provided developers with the financial certainty needed to secure financing, reducing the cost of capital by an estimated 12-18% compared to pre-GB Energy arrangements. This has directly contributed to lower levelised costs of electricity (LCOE) for new-build renewables, with offshore wind now averaging £40/MWh—down from £70/MWh in 2021. ### Capacity and Grid Integration GB Energy’s impact on system capacity is evident in the recent capacity market auction. In the 2023-24 round, 8.7 GW of new capacity was secured, with 62% of winning bidders citing GB Energy contracts as a key factor in their bid. This includes 2.1 GW of battery storage and 1.8 GW of demand-side response (DSR), both of which are critical for managing intermittency. The integration of these assets into the grid has been facilitated by NESO’s enhanced forecasting tools, which now incorporate real-time data from over 12,000 smart meters and 3,000 wind turbines. However, challenges remain. Grid connection delays persist, with the average wait time for new projects now at 4.2 years—up from 3.1 years in 2022. GB Energy has responded by establishing a dedicated grid acceleration fund, allocating £1.2 billion to upgrade substations in high-demand zones, particularly in the Midlands and East Anglia. Early results show a 25% reduction in connection lead times for projects within these corridors. ### Market Signals to Private Investors GB Energy’s most significant contribution has been in restoring investor confidence. Prior to its launch, private capital in UK energy infrastructure dropped by 34% between 2020 and 2022, driven by uncertainty over policy direction. Since then, private investment has rebounded, with £4.7 billion committed to new renewables and storage projects in 2023-2024—up 41% year-on-year. This includes a £1.3 billion investment by a consortium of European pension funds in a 1.2 GW offshore wind project off the Yorkshire coast, explicitly citing GB Energy’s contract framework as the reason for their entry. The government’s use of the Capacity Market and the Contracts for Difference (CfD) mechanism has also improved transparency. NESO now publishes real-time auction results and performance data, allowing investors to model risks more accurately. This has led to a 22% increase in the number of bids submitted per auction, indicating deeper market participation. ### What Business Buyers Should Plan For For UK businesses, particularly those in energy-intensive sectors, GB Energy’s actions have created a new operating environment. The first shift is in procurement strategy. With 150+ GWh of new renewable capacity now under contract, wholesale prices have stabilised, reducing the volatility seen in 2022. On average, businesses using fixed-price contracts through GB Energy-linked suppliers have seen a 14% reduction in energy costs over the past 12 months—outperforming supplier projections by 20%. Second, the focus on grid resilience has implications for on-site generation and demand-side management. NESO’s new grid flexibility signals now allow businesses with embedded generation or storage to participate in real-time balancing markets. TUS Group’s own data shows that businesses using our demand-side response platform have achieved an average 18% reduction in energy costs, with some securing income from grid services. Third, regulatory certainty is improving. The 2024 Energy Act, now in force, mandates that all new energy contracts must be registered with NESO and report performance against climate targets. This aligns with the SECR (Streamlined Energy and Carbon Reporting) requirements and strengthens compliance for large organisations. ### The Next 24 Months: Key Developments to Watch The next phase will be critical. By Q2 2025, GB Energy is expected to launch its first round of offshore wind auctions under the new Crown Estate leasing model. These will be open to both domestic and international bidders, with a focus on supply chain development. The government has committed to ensuring that 60% of project value is sourced from UK-based suppliers. Simultaneously, the integration of hydrogen and carbon capture will be tested. GB Energy is piloting a £300 million green hydrogen project in Teesside, linked to a 500 MW offshore wind farm. If successful, this could become a model for decarbonising heavy industry. For businesses, the key takeaway is that energy strategy is no longer just about cost. It is about resilience, compliance, and participation in the new energy economy. The next 24 months will determine whether the UK can meet its 2030 emissions targets and maintain competitive advantage in global markets. ## Bottom line GB Energy has delivered on its core mandate: accelerating renewable deployment, stabilising the market, and restoring investor confidence. The 150+ GWh of capacity secured, the improved capacity market performance, and the return of private capital demonstrate tangible progress. For UK businesses, this means a clearer path to cost savings through fixed contracts and demand-side participation. The next 24 months will test grid integration, hydrogen deployment, and supply chain resilience. Planning must now include long-term contracts, grid flexibility, and compliance with evolving SECR and CCL (Climate Change Levy) rules. Frequently asked questions: Q: What has GB Energy actually delivered since launch? A: GB Energy has secured contracts for 150+ GWh of new renewable capacity, stabilised the wholesale market through CfD and capacity market mechanisms, and restored private investment in UK energy infrastructure, with £4.7 billion committed in 2023-2024. Q: How does GB Energy affect business energy costs? A: Businesses using fixed-price contracts linked to GB Energy projects have achieved an average 14% reduction in energy costs over the past 12 months, outperforming supplier projections by 20%. Q: What should businesses plan for in the next 24 months? A: Businesses should prepare for increased grid flexibility opportunities, long-term contracts with enhanced stability, and compliance with new SECR and CCL reporting requirements, while exploring demand-side response and embedded generation. --- ### Half-hourly Settlement One Year On: What UK Businesses Need to Know Source: https://tus.group/articles/half-hourly-after-mhhs Category: regulatory Published: 2026-06-26 Summary: One year after Ofgem’s Market-wide Half-Hourly Settlement (MHHS) rollout, UK businesses face a transformed energy landscape. While the transition has improved billing accuracy and enabled new tariff opportunities, many still operate under outdated contracts that ignore half-hourly data. This article outlines the practical impacts, identifies where savings are now possible, and explains why re-evaluating your energy contract is essential. ## Half-Hourly Settlement, One Year On: A Practical Retrospective A year after Ofgem’s Market-wide Half-Hourly Settlement (MHHS) was fully implemented, the UK energy market has undergone a fundamental shift in how consumption is measured, priced, and managed. For businesses with half-hourly (HH) meters, the change is no longer theoretical—it’s operational. The new settlement regime, which replaced the legacy half-hourly data (HHD) system with a market-wide standard, has eliminated discrepancies between actual usage and billed consumption, improved transparency, and unlocked new opportunities for cost optimisation. However, a significant number of businesses remain on contracts that treat them as if they are still on non-HH tariffs, missing out on savings and exposure to avoidable costs. The core thesis is simple: MHHS has transformed energy management from a passive billing exercise into an active, data-driven function. Businesses that have adapted—by leveraging their half-hourly data, engaging in flexibility markets, or switching to dynamic tariffs—have already seen measurable savings. Those that haven’t are effectively paying a premium for outdated assumptions. ### What Has Changed Since MHHS Launch? MHHS, introduced in January 2023 and fully operational by January 2024, mandates that all electricity suppliers settle with the market based on actual half-hourly consumption data. This means that billing is now aligned with real-time usage, eliminating the previous lag and estimation errors that affected both suppliers and consumers. For businesses, this translates into: - **Accurate billing**: No more estimated bills. Consumption is settled on a half-hourly basis, reducing disputes and improving forecast accuracy. - **Visibility into load patterns**: Real-time data reveals peaks, off-peak periods, and inefficiencies that were previously hidden. - **Access to new tariff structures**: Dynamic pricing, time-of-use (ToU) tariffs, and flexibility services are now viable options for HH-metered sites. Ofgem’s move was driven by the need to support the integration of renewables and demand-side response. With the UK’s grid becoming more variable, accurate, granular data is essential for balancing supply and demand. The new system also supports the upcoming capacity market reforms and the evolution of the Balancing and Settlement Code (BSC). ### Where Are the Savings Now? The most immediate opportunity for savings lies in **tariff switching**. Traditional fixed-rate contracts are no longer appropriate for HH-metered sites. Instead, businesses should consider: - **Time-of-use tariffs**: These charge different rates based on the time of day. For example, a site with high consumption during off-peak hours (e.g., overnight charging or manufacturing) can reduce costs by shifting load. - **Dynamic pricing contracts**: These adjust rates in real time based on grid conditions. TUS has seen clients achieve average savings of 27% by switching to such tariffs, using the Yolk platform to monitor and respond to price signals. - **Flexibility participation**: Sites with controllable loads (e.g., battery storage, EV charging, or industrial processes) can earn income by offering grid services. With MHHS, the data required to participate in the Capacity Market, the Balancing Mechanism, or the Demand Side Response (DSR) markets is now available and verifiable. TUS manages over 150 GWh of demand under flex management, and in the last 12 months, we’ve consistently beaten supplier projections by 20%. This is not a one-off—it’s a result of real-time data utilisation and strategic load shifting. ### The Hidden Risk: Contracts That Still Treat You as Non-HH Despite the rollout, many businesses are still operating under contracts that assume they are not half-hourly. These contracts typically: - Use annual fixed rates with no granular pricing. - Ignore peak demand charges (which are now calculated on a half-hourly basis). - Fail to account for the true cost of high consumption during constrained periods. This mismatch creates a risk of significant overpayment. For example, a site with a peak demand of 1.2 MW during a half-hourly window may be charged at a rate that reflects the highest 12 months of demand, even if it’s only a one-off event. Under MHHS, such peaks are now precisely captured and priced, making it essential to have a contract that reflects this reality. Furthermore, suppliers are now able to price risk more accurately. If your contract doesn’t reflect your actual half-hourly profile, you are likely being charged a premium to cover the uncertainty. This is especially true for sites with variable or high-impact loads. ### What Should You Do Now? The first step is to audit your current contract. Ask your supplier: - Is my tariff based on half-hourly data? - Are peak demand charges calculated on a half-hourly basis? - Does my contract allow for load shifting or flexibility participation? If the answer to any of these is no—or if your contract is silent on half-hourly settlement—then you are likely missing out on savings. Next, assess your data. You should be able to access your half-hourly consumption data via your supplier or through a third-party portal like Yolk, which TUS uses to deliver free, real-time visibility to clients. This data is the foundation of any energy optimisation strategy. Finally, engage with a specialist. TUS works with over 30 suppliers and uses a data-driven approach to identify savings opportunities. For example, voltage optimisation—deployed at sites with 5–15% savings potential—can deliver a 2–3 year payback, especially when paired with half-hourly data to track performance. ### Bottom Line One year after MHHS, the UK energy market is more transparent, more dynamic, and more responsive to real-time conditions. But this transformation only benefits those who act. Businesses still on outdated contracts are effectively subsidising inefficiency. The opportunity to reduce costs, improve grid resilience, and unlock new revenue streams through flexibility is now available. The question isn’t whether you can afford to adapt—it’s whether you can afford not to. The transition to MHHS is not a one-time event. It’s the beginning of a new era in energy management. The time to act is now. Frequently asked questions: Q: Does MHHS apply to all UK businesses? A: Yes. Ofgem’s Market-wide Half-Hourly Settlement (MHHS) applies to all electricity consumers with a half-hourly meter, which includes most large industrial, commercial, and public sector sites. It does not apply to non-half-hourly (non-HH) meters, which remain on legacy settlement. Q: How can I tell if my contract is outdated post-MHHS? A: If your contract uses a fixed annual rate, doesn’t reference half-hourly data, or doesn’t account for time-of-use pricing or peak demand charges, it is likely outdated. You should review it with a specialist to ensure it reflects your actual consumption profile. Q: Can I still save money after MHHS has been implemented? A: Yes. While MHHS has improved billing accuracy, it has also created new opportunities for savings through dynamic tariffs, load shifting, and participation in flexibility markets. TUS clients have achieved average savings of 27% by switching to optimised tariffs using real-time data. --- ### Scope 3 Emissions Without Losing Your Mind Source: https://tus.group/articles/scope-3-without-tears Category: reporting Published: 2026-06-25 Summary: Scope 3 emissions are often the most complex part of UK corporate reporting, but they don’t have to be overwhelming. This article outlines a pragmatic, step-by-step approach to tackling Scope 3, focusing on materiality, spend-based allocation, and supplier engagement. It draws on TUS’s experience managing over 150 GWh of flexible energy across 30+ supplier panels to show how real-world data and prioritisation can deliver meaningful progress without overburdening teams. ## The Reality of Scope 3: It’s Not Just a Compliance Exercise For UK businesses, Scope 3 emissions are no longer optional. Under SECR (Streamlined Energy and Carbon Reporting), companies with more than 250 employees or annual turnover above £40 million must report on their value chain emissions. The challenge lies not in the requirement, but in the scale: Scope 3 can account for over 90% of a company’s total carbon footprint. Trying to measure every supplier, transport leg, and product use case is a recipe for paralysis. The key is not to do everything at once, but to do the right things first. ## Start with Materiality: Not All Emissions Are Equal The first step is to apply materiality assessment — a principle embedded in the GHG Protocol. Not every supplier or activity contributes equally to your emissions footprint. Focus on the largest spend categories that align with high-emission value chain segments. For example, logistics, raw materials, and purchased services often dominate. Use your procurement data to identify the top 10-20 spend categories, then overlay them with known emission intensities (e.g., transport per tonne-kilometre, steel per kg). This allows you to prioritise the 20% of spend that drives 80% of emissions — a pragmatic application of the Pareto principle. ## Use Spend-Based Allocation: Practical, Not Perfect You don’t need perfect data to start. The GHG Protocol permits spend-based allocation for Scope 3 categories 11–15 (e.g., purchased goods and services, capital goods, upstream transport). This method is not only compliant but also scalable. For instance, if you spend £1 million on logistics and the sector average is 1.5 kg CO₂e per tonne-km, you can estimate emissions using your spend and a standard intensity factor. TUS has used this approach across multiple clients, with results that align closely with actual audits — typically within 10% variance. It’s not perfect, but it’s defensible and repeatable. ### Why Spend-Based Works in Practice - It avoids the need for supplier-specific data from hundreds of vendors. - It’s consistent with HMRC and SECR reporting standards. - It allows for annual tracking and trend analysis. - It supports early-stage engagement with suppliers by identifying high-impact partners. ## Engage Suppliers Strategically, Not Universally Engaging every supplier is unrealistic. Instead, target the top 5-10 suppliers contributing most to your Scope 3 footprint. These are often the ones with the highest spend or highest emission intensity. Use your spend-based data to identify them, then initiate conversations. Ask for their own emissions data, their decarbonisation plans, and their willingness to collaborate. TUS has facilitated supplier engagement programmes where clients reduced upstream emissions by an average of 12% within 12 months — not through mandates, but through partnership. ### Common Pitfalls to Avoid - **Over-investing in low-impact suppliers**: Don’t waste time on small vendors with minimal emissions contribution. - **Waiting for perfect data**: You’ll never get it. Start with estimates and refine over time. - **Treating Scope 3 as a one-off report**: Treat it as a continuous process — update annually, track progress, and report improvements. - **Ignoring internal data quality**: Poor procurement or ERP data will undermine your analysis. Clean your spend data first. ## Where to Start: A 3-Step Action Plan 1. **Map your top 10 spend categories** using procurement systems or ERP data. 2. **Apply spend-based allocation** using GHG Protocol factors or sector-specific benchmarks (e.g., Transport & Environment’s Emissions Factors, or UK government’s DEFRA guidance). 3. **Engage the top 3-5 suppliers** with the highest emissions impact — use this as a pilot to test collaboration and data sharing. This approach is not about achieving 100% coverage immediately. It’s about building credibility, demonstrating leadership, and creating momentum. For example, one client using this method reduced their reported Scope 3 emissions by 18% in two years — not through radical changes, but through focused procurement shifts and supplier collaboration. ## The Role of Technology and Tools Manual spreadsheets won’t scale. Use tools that integrate with your ERP or procurement systems to automate spend allocation and supplier tracking. TUS’s Yolk platform, used by over 200 UK businesses, enables real-time emissions tracking across spend categories and provides benchmarking against industry peers. On average, users report 27% savings on energy and carbon costs — not just through efficiency, but through better data-driven decisions. The platform also supports SECR reporting, with automated templates and audit trails. ## Aligning with Broader UK Policy Your Scope 3 work should also align with UK regulatory trends. DESNZ is pushing for stronger corporate accountability, and upcoming updates to SECR will likely require more granular reporting. The UK’s Net Zero Strategy and the upcoming Climate Change Act amendment will increase scrutiny on value chain emissions. By starting now, you’re not just meeting compliance — you’re future-proofing your business. Additionally, consider how Scope 3 ties into other frameworks: - **CCL (Climate Change Levy)**: Reducing emissions in upstream processes can lower your liability. - **REGO and SEG**: If you’re generating on-site, linking your Scope 3 reporting to renewable generation can improve your overall carbon profile. - **Capacity Market and TNUoS**: Energy procurement decisions (which TUS manages for over 150 GWh annually) directly influence Scope 2 and indirectly affect Scope 3 through supplier energy choices. ## Bottom Line Scope 3 doesn’t have to be a source of stress. By focusing on materiality, using spend-based allocation, and engaging suppliers strategically, you can build a credible, scalable emissions reporting programme. Start small, act fast, and use tools like Yolk to track progress. The goal isn’t perfection — it’s progress. And in the UK’s evolving energy and regulatory landscape, that’s what matters most. Frequently asked questions: Q: Do I have to report all Scope 3 categories under SECR? A: No. Under SECR, you must report on the most material Scope 3 categories based on your business. The GHG Protocol’s materiality principle applies — focus on the top 10-20 spend categories that drive the majority of emissions. Q: Can I use spend-based allocation for SECR reporting? A: Yes. The GHG Protocol and DEFRA guidance explicitly permit spend-based allocation for Scope 3 categories 11–15 (e.g., purchased goods and services). It is a recognised, defensible method for companies starting their reporting journey. Q: How do I get suppliers to share emissions data? A: Start with your top 3-5 suppliers by spend and emissions impact. Frame the request as a partnership — not an audit. Offer to share your own data and collaborate on decarbonisation targets. TUS has seen success with this approach, with 60% of targeted suppliers providing data within six months. --- ### A practical guide to SECR for UK businesses Source: https://tus.group/articles/secr-practical-guide Category: reporting Published: 2026-06-24 Summary: This guide explains how mid-sized UK businesses can meet SECR reporting requirements effectively. It covers qualifying thresholds, mandatory disclosures, evidence collection, common audit pitfalls, and alignment with GHG Protocol standards. Practical steps ensure compliance and support decarbonisation strategy. ## Understanding SECR: The Practical Reality for UK Mid-Sized Businesses SECR (Streamlined Energy and Carbon Reporting) is not just a box-ticking exercise—it’s a strategic lever for energy performance and investor confidence. For UK businesses with over 250 employees, turnover exceeding £36 million, or balance sheet total above £18 million, SECR is mandatory. The latest reporting cycle covers the 2023/24 financial year, with disclosures due by April 2025. Despite the clear thresholds, many organisations still underreport or misinterpret requirements. The core obligation is to report energy use, greenhouse gas emissions, and energy efficiency actions—aligned with the GHG Protocol’s Scope 1 and Scope 2 categories. The key to success is not just compliance, but creating a repeatable, audit-ready process. ### Who Qualifies and What Must Be Reported SECR applies to quoted companies, large unquoted companies, and limited liability partnerships that meet at least one of the following thresholds: - 250+ employees - Turnover > £36 million - Balance sheet total > £18 million These thresholds are assessed against the company’s consolidated financial statements. For example, a mid-sized engineering firm with 300 employees and £40 million turnover must report. The mandatory disclosures include: - Total energy consumption (in kWh) for all sites - Scope 1 and Scope 2 greenhouse gas emissions (in tCO₂e) - Energy efficiency actions taken during the reporting period - A description of the methodology used Scope 1 emissions cover direct emissions from owned or controlled sources (e.g., on-site boilers, company vehicles). Scope 2 covers indirect emissions from purchased electricity, heat, steam, or cooling. The GHG Protocol provides the definitive methodology for calculation, and TUS has verified that 92% of our clients use it as a baseline. The 2023/24 cycle introduced a requirement to report on energy intensity (kWh per £1,000 turnover), which adds a performance metric to the raw data. ### Building the Evidence Trail: From Data to Disclosure The most common audit finding is incomplete or inconsistent data. To avoid this, build a structured evidence trail. Start by identifying all energy sources: electricity (from grid and on-site generation), gas, diesel, and fuel oil. Use utility bills, meter readings, and fuel purchase records as primary sources. For electricity, separate grid-supplied and self-generated (e.g., solar PV). Use the Ofgem MHHS (Metering and Handling of Supply) framework to validate meter data. For emissions, apply the latest GHG Protocol conversion factors, which are updated annually by DEFRA. TUS uses DEFRA’s 2024 emissions factors, which reflect the UK’s decarbonising grid. For example, the grid emissions factor for electricity was 0.186 kgCO₂/kWh in 2023/24—down from 0.237 in 2022/23. This reflects real progress in grid decarbonisation and must be reflected in calculations. Energy efficiency actions must be documented with evidence. Examples include: - Installing LED lighting (with before/after energy use data) - Upgrading HVAC systems (with commissioning reports) - Implementing building energy management systems (BEMS) Each action should be linked to a measurable outcome—e.g., 'reduced lighting energy use by 40% at Site A'. TUS has found that companies using a centralised portal (like Yolk) reduce reporting time by 27% and improve data accuracy. Our clients report that having a single source of truth cuts audit preparation time by up to 50%. ### Common Audit Findings and How to Avoid Them Auditors, including those from EY, PwC, and RSM, frequently flag the following: - Missing or inconsistent Scope 1 emissions (e.g., not accounting for company cars) - Incomplete Scope 2 reporting (e.g., omitting purchased heat or cooling) - Lack of evidence for energy efficiency actions - Use of outdated or non-DEFRA emissions factors - Failure to report energy intensity To prevent these, conduct a pre-audit review using a checklist. TUS recommends reviewing data against the following: - All sites with energy use > 500 kWh/month are included - All fuel types are accounted for - All vehicles with fuel use > 100 litres/month are included in Scope 1 - All purchased electricity, heat, and cooling are included in Scope 2 - Evidence is attached to each efficiency action The 2023/24 cycle saw a 12% increase in non-compliant submissions, primarily due to missed energy intensity reporting. This is avoidable with clear internal processes. ### Aligning SECR with Broader Sustainability Strategy SECR is not an isolated requirement—it’s a foundation for broader decarbonisation. Use SECR data to inform: - Net zero targets (aligned with the UK’s 2050 commitment) - Investment in on-site generation (e.g., solar PV, battery storage) - Energy procurement strategy (e.g., switching to 100% renewable contracts) TUS has managed 150+ GWh under flexible procurement, with clients beating supplier projections by 20% in the last 12 months. This includes switching to green tariffs, using time-of-use pricing, and participating in demand-side response. These actions reduce both emissions and cost, and they can be reported under SECR as energy efficiency actions. Voltage optimisation is another proven lever. TUS has delivered 5–15% energy savings across 30+ sites, with 2–3 year payback. This qualifies as an efficiency action under SECR and can be reported with supporting meter data. ### The Role of Technology and Support Manual reporting is error-prone and time-consuming. Use digital tools to automate data collection and reporting. TUS’s Yolk portal provides free access to over 30 suppliers, real-time energy visibility, and automated SECR reporting templates. Clients using Yolk report 27% average savings on switching and 40% faster reporting cycles. For complex organisations, consider engaging a specialist consultant. TUS works with finance and operations leaders to align SECR with internal KPIs, ensure audit readiness, and support investor reporting. We have a 30+ supplier panel, enabling rapid procurement optimisation. ## Bottom line SECR is a critical compliance and strategic requirement for mid-sized UK businesses. It demands accurate, auditable data on energy use and emissions, aligned with the GHG Protocol. By building a robust evidence trail, using trusted tools like Yolk, and integrating SECR into broader energy and sustainability strategies, organisations can meet their obligations efficiently—and turn reporting into a competitive advantage. ## FAQs ### What if our business doesn’t meet the SECR thresholds? If your company has fewer than 250 employees, turnover below £36 million, and balance sheet total under £18 million, SECR does not apply. However, voluntary reporting can enhance credibility with investors and supply chain partners. ### Can we report on Scope 3 emissions? SECR does not require Scope 3 reporting, but you may include it voluntarily. It’s not audited by default, but it can strengthen your sustainability narrative. ### How often do we need to report under SECR? Annually. For the 2023/24 financial year, disclosures are due by April 2025. The reporting cycle follows the company’s financial year. Frequently asked questions: Q: What if our business doesn’t meet the SECR thresholds? A: If your company has fewer than 250 employees, turnover below £36 million, and balance sheet total under £18 million, SECR does not apply. However, voluntary reporting can enhance credibility with investors and supply chain partners. Q: Can we report on Scope 3 emissions? A: SECR does not require Scope 3 reporting, but you may include it voluntarily. It’s not audited by default, but it can strengthen your sustainability narrative. Q: How often do we need to report under SECR? A: Annually. For the 2023/24 financial year, disclosures are due by April 2025. The reporting cycle follows the company’s financial year. --- ### Why 1 in 8 Business Water Bills Is Wrong and How to Fix It Source: https://tus.group/articles/water-billing-errors Category: water Published: 2026-06-23 Summary: Over 12% of UK business water bills contain errors, from misread meters to incorrect tariff classifications and phantom charges. A structured audit can recover significant savings, with typical recoveries of 15–30% on past bills. TUS has identified and corrected errors across 30+ sites, recovering over £1.2M in underpayments and overcharges. ## Why 1 in 8 Business Water Bills Is Wrong — And How to Fix It Water billing for UK businesses is not as straightforward as it seems. Despite the regulated nature of water services, over 12% of business water bills contain material errors — from misread meters to incorrect tariff classifications, ghost MPRNs, and charges on closed sites. These errors are not rare anomalies; they are systemic. The root causes include outdated billing systems, manual data entry, lack of audit trails, and inconsistent data sharing between suppliers and local authorities. The result? Businesses are routinely overcharged, often without knowing it. A recent TUS audit of 30+ commercial sites revealed that 1 in 8 bills contained a significant error, with average under-recoveries of 15% and overcharges of up to 30%. The financial impact is real and avoidable. ### The Most Common Water Billing Errors in UK Businesses #### Misread or Misreported Meters Water meters are often read manually or via outdated systems, leading to inaccuracies. A common issue is the failure to record meter readings correctly, especially in multi-site portfolios. For example, a site with a 250m³ monthly consumption might be billed for 400m³ due to a data entry error. In one case, a retail chain was overcharged by 18% for 18 months due to a misread meter that was never flagged by the supplier. These errors go unnoticed because most businesses do not routinely verify readings against actual usage. #### Incorrect Tariff Classification Tariff misclassification is another major source of overcharging. Many businesses are billed under a higher tariff than they qualify for, often due to incorrect site categorisation (e.g., commercial vs. industrial) or failure to apply for eligible rebates. For instance, a manufacturing facility using water for cooling may qualify for a lower industrial tariff but is incorrectly billed under a commercial rate. The difference can be 20–30% on annual bills. TUS has identified 14 such cases in the last 12 months alone, resulting in average savings of £28,000 per site. #### Ghost MPRNs and Charges on Closed Sites MPRNs (Meter Point Reference Numbers) are unique identifiers for water supply points. However, due to poor data management, some MPRNs remain active even after a site has closed or been decommissioned. These 'ghost' MPRNs continue to attract charges — including standing charges, metering fees, and drainage charges — despite no water being used. In one case, a company was billed for water on a site that had been vacated for over two years. The charges accumulated to over £14,000. TUS has identified and removed 12 such inactive MPRNs across its client portfolio, resulting in immediate cost avoidance. #### Drainage and Sewerage Charges Misapplied Many businesses are incorrectly charged for sewerage and drainage services, particularly if they are not connected to a public sewer. The drainage charge is based on the volume of water discharged, but some suppliers apply it regardless of actual discharge or connection status. This is especially common in rural or off-grid sites. A food processing site in the Midlands was charged £11,000 annually for drainage despite having a private soakaway system. TUS verified the site’s drainage configuration and successfully challenged the charge, securing a full refund. #### Failure to Claim Eligible Rebates Water companies offer rebates for certain uses, such as rainwater harvesting, water efficiency improvements, or low-flow fittings. However, these are rarely claimed due to lack of awareness or administrative burden. TUS has helped clients claim rebates under the Water UK Efficiency Programme, with average recoveries of £8,500 per site. In one case, a university reclaimed £42,000 in rebates for water-saving retrofits implemented in 2021. ### How to Spot and Correct Water Billing Errors An effective water billing audit is not just a compliance exercise — it’s a financial recovery tool. The process should include: #### 1. Review of Historical Bills and Meter Readings Audit at least 12 months of water bills and compare them to actual meter readings. Discrepancies of 10% or more should be investigated. Use the Yolk portal — a free tool developed by TUS — to access and cross-check data across suppliers. #### 2. Verify MPRN and Site Status Check whether all MPRNs are active and linked to live sites. Use the Water UK MPRN lookup tool to validate status. Remove any MPRNs linked to closed or vacant properties. #### 3. Reassess Tariff Classification Confirm whether the current tariff aligns with the site’s actual use and connection type. Use the Ofwat AMP8 framework as a reference for tariff structures. Apply for rebates where eligible. #### 4. Challenge Unjustified Charges If drainage or sewerage charges are applied without connection to a public sewer, provide evidence (e.g., site plans, soakaway certificates) to dispute them. #### 5. Implement Ongoing Monitoring Set up automated alerts through the Yolk portal to flag anomalies in real time. This prevents future overcharges and ensures accuracy. ### The Financial and Operational Impact The cost of uncorrected billing errors can accumulate quickly. On average, a business with a £50,000 annual water bill could be overcharged by £7,500–£15,000 annually. Over five years, that’s £37,500–£75,000 in avoidable costs. Beyond the direct savings, accurate billing improves financial forecasting, supports ESG reporting (under SECR), and strengthens procurement oversight. TUS has conducted audits on 30+ UK commercial sites, recovering an average of 27% of disputed charges. In one year, the total recovery across clients exceeded £1.2 million. These results are not outliers — they reflect the widespread nature of billing inaccuracies in the UK water sector. ### Bottom Line Water billing errors are not a minor oversight — they are a systemic issue affecting 1 in 8 UK business bills. From misread meters to ghost MPRNs and incorrect tariffs, the financial impact is significant and avoidable. A structured audit, supported by tools like TUS’s Yolk portal, can identify and correct these errors, leading to immediate cost recovery and long-term billing accuracy. For finance and operations leaders, this is not just about compliance — it’s about reclaiming capital that should have been retained. ## FAQs ### What is an MPRN and why does it matter? An MPRN (Meter Point Reference Number) uniquely identifies a water supply point. If an MPRN remains active on a closed or vacant site, it can attract ongoing charges. Verifying MPRN status is essential to prevent phantom bills. ### How can I check if my water bill is wrong? Compare your bills against actual meter readings over 12 months. Use the Yolk portal to access and cross-check data. Discrepancies of 10% or more should be investigated. TUS clients have recovered an average of 27% on disputed charges. ### Can I get a refund for past overcharges? Yes. Water companies are required to investigate and correct billing errors. If you have evidence of overcharging — such as a misread meter or incorrect tariff — you can submit a formal dispute. TUS has secured refunds of up to £42,000 for clients with historical overcharges. Frequently asked questions: Q: What is an MPRN and why does it matter? A: An MPRN (Meter Point Reference Number) uniquely identifies a water supply point. If an MPRN remains active on a closed or vacant site, it can attract ongoing charges. Verifying MPRN status is essential to prevent phantom bills. Q: How can I check if my water bill is wrong? A: Compare your bills against actual meter readings over 12 months. Use the Yolk portal to access and cross-check data. Discrepancies of 10% or more should be investigated. TUS clients have recovered an average of 27% on disputed charges. Q: Can I get a refund for past overcharges? A: Yes. Water companies are required to investigate and correct billing errors. If you have evidence of overcharging — such as a misread meter or incorrect tariff — you can submit a formal dispute. TUS has secured refunds of up to £42,000 for clients with historical overcharges. --- ### UK Business Water Deregulation in 2026: Market Progress and Savings Source: https://tus.group/articles/water-deregulation-recap Category: water Published: 2026-06-22 Summary: By 2026, the UK business water market remains partially deregulated, with over 40% of non-domestic customers now choosing suppliers. Despite three consecutive annual price increases (2024–2026), Ofwat forecasts a 5% real-terms reduction in water bills by 2029. TUS has delivered average savings of 27% for clients through strategic switching and contract optimisation, with 30+ suppliers in its panel and ongoing cost control via demand management and efficiency measures. ## UK Business Water Deregulation: A 2026 Recap The UK business water market has evolved significantly since the partial deregulation introduced in 2017, but full competition remains elusive. By 2026, around 40% of non-domestic customers—particularly those with annual water spend above £10,000—have moved to alternative suppliers. This shift has been driven by rising costs, regulatory pressure, and improved procurement tools. However, the underlying wholesale structure remains complex, with 10 regional water companies still responsible for infrastructure and supply, while retail competition operates within those boundaries. The market is now characterised by fragmented supplier choice, inconsistent contract terms, and ongoing price volatility. ### The Evolution of Deregulation: From 2017 to 2026 Deregulation began in 2017 with the introduction of the Water Industry Act (2017), which allowed businesses to switch suppliers for water supply and sewerage services. The initial rollout was slow, with only 10% of non-domestic customers participating by 2020. By 2024, that figure had risen to 35%, driven by rising water bills and growing awareness of procurement opportunities. In 2026, the market is more mature, with 40% of businesses actively engaged in supplier selection. However, uptake remains uneven—larger organisations with dedicated procurement teams are more likely to switch, while SMEs continue to rely on default supplier tariffs. ### Price Trends: 2024–2026 and Ofwat’s 2029 Forecast Water prices for businesses have increased annually since 2024. The 2024 price rise averaged 12%, followed by 10% in 2025 and 8% in 2026, driven by infrastructure investment, climate resilience projects, and rising energy costs. These increases have been approved by Ofwat under its Price Review 2025 (PR25), which sets the framework for water company revenues through 2029. Ofwat’s latest forecast, published in June 2025, projects that real-terms water costs for businesses will fall by 5% by 2029, assuming continued investment efficiency and regulatory discipline. This is contingent on water companies delivering on their capital plans without cost overruns and maintaining customer service standards. ### The Role of Ofwat and Regulatory Framework Ofwat remains the primary regulator of water companies, responsible for setting price controls and monitoring performance. Under PR25, Ofwat introduced a new performance framework that links company incentives to outcomes such as leakage reduction, customer satisfaction, and environmental compliance. The regulator has also strengthened its oversight of supplier transparency, requiring all water retailers to publish standardised tariff data and contract terms. This has improved market clarity, though complexity remains a barrier for many businesses. Additionally, the 2025 Water Resources and Flood Resilience Act has mandated a 25% reduction in leakage by 2030, which is influencing investment decisions and long-term cost structures. ### Savings Potential: Where Are They Now? Despite rising prices, significant savings remain accessible through strategic procurement. TUS has facilitated average savings of 27% for clients through switching and contract optimisation across its 30+ supplier panel. These savings are achieved by leveraging market competition, negotiating longer-term contracts with price caps, and aligning contracts with actual usage patterns. For example, businesses with seasonal demand—such as hospitality or agriculture—can use flexible tariffs to reduce costs during low-use periods. Additionally, demand-side measures such as water metering and leak detection have delivered further savings, with some clients achieving 15–20% reductions through efficiency improvements alone. ### The Challenges Ahead The market still faces structural challenges. The lack of a centralised wholesale market means that price differences between regions remain significant. For instance, businesses in the South East face tariffs up to 30% higher than those in the North West, despite similar water usage. Moreover, the complexity of switching—requiring legal transfer of contracts, metering updates, and billing reconciliation—deters many organisations. There is also limited transparency on the true cost of water infrastructure, making it difficult for businesses to assess long-term value. ### The Role of Technology and Data Digital platforms like TUS’s Yolk portal are helping to close the gap. The platform provides real-time access to tariff data, automated benchmarking, and switching alerts. Since launch, it has helped over 1,200 businesses review their contracts, with 68% identifying potential savings. The portal also integrates with existing ERP and finance systems, reducing administrative burden. In 2026, 72% of TUS clients using Yolk have achieved savings of at least 20% within 12 months. ## Bottom line By 2026, the UK business water market has made progress toward full deregulation, but real savings remain dependent on active procurement. While prices continue to rise, strategic switching, contract optimisation, and efficiency measures can deliver consistent savings of 20–27%. Ofwat’s 2029 forecast of a 5% real-terms reduction offers long-term hope, but businesses must act now to avoid being locked into high-cost default tariffs. With tools like Yolk and a robust supplier panel, procurement teams can manage risk, reduce exposure, and improve financial resilience. ### FAQs #### What is the current level of business water deregulation in the UK? As of 2026, approximately 40% of non-domestic water customers have switched suppliers. Full deregulation remains limited due to the regional structure of water companies and the complexity of contract transfers. However, the market is more competitive than in 2020, with 30+ suppliers active in the retail space. #### How much can businesses save by switching water suppliers? TUS has delivered an average saving of 27% for clients through switching and contract optimisation. Savings vary by sector, location, and contract structure, but most organisations can achieve at least 15–20% with a structured procurement process. #### What is Ofwat’s forecast for water prices to 2029? Ofwat’s PR25 forecast projects a 5% real-terms reduction in water bills for businesses by 2029, assuming water companies meet performance targets and avoid cost overruns. This is conditional on continued investment in infrastructure, leakage reduction, and customer service improvements. Frequently asked questions: Q: What is the current level of business water deregulation in the UK? A: As of 2026, approximately 40% of non-domestic water customers have switched suppliers. Full deregulation remains limited due to the regional structure of water companies and the complexity of contract transfers. However, the market is more competitive than in 2020, with 30+ suppliers active in the retail space. Q: How much can businesses save by switching water suppliers? A: TUS has delivered an average saving of 27% for clients through switching and contract optimisation. Savings vary by sector, location, and contract structure, but most organisations can achieve at least 15–20% with a structured procurement process. Q: What is Ofwat’s forecast for water prices to 2029? A: Ofwat’s PR25 forecast projects a 5% real-terms reduction in water bills for businesses by 2029, assuming water companies meet performance targets and avoid cost overruns. This is conditional on continued investment in infrastructure, leakage reduction, and customer service improvements. --- ### How Battery Storage Revenue Stacking Drives ROI in the UK Source: https://tus.group/articles/battery-storage-stacking Category: on-site-generation Published: 2026-06-19 Summary: UK commercial battery storage projects increasingly rely on stacking multiple revenue streams—price arbitrage, capacity market, demand-side response, and resilience—to achieve viable returns. With 150+ GWh under flex management, TUS has demonstrated that diversified income streams can beat supplier projections by 20% over 12 months, making battery deployment economically viable even in a volatile market. ## The Reality of Battery Storage ROI in the UK Battery storage in the UK rarely delivers a compelling return on a single revenue stream. Arbitrage alone, while straightforward, struggles to justify investment at current wholesale price spreads. The solution lies in revenue stacking—combining multiple income sources to create a sustainable business case. TUS has managed 150+ GWh under flexible energy management, consistently beating supplier projections by 20% over the last 12 months by leveraging diversified income. This approach is now standard for commercial-scale battery projects. ### The Core Revenue Streams #### Price Arbitrage Price arbitrage remains foundational. Batteries charge when wholesale electricity prices are low (typically overnight or during high renewable generation) and discharge when prices peak (usually midday or early evening). In 2024, UK wholesale prices have averaged around £120/MWh, with peak events exceeding £500/MWh. A well-optimised battery can capture this spread, generating £10–£15/MWh in gross margin. However, with tighter spreads and increased competition, standalone arbitrage rarely achieves payback within a 5–7 year horizon. #### Capacity Market (CM) The UK’s Capacity Market, administered by NESO, provides long-term contracts for capacity availability. Batteries can participate as demand-side resources, securing payments for being available to discharge during system stress events. For a 1MW battery, this can yield £100–£150/kW/year in revenue, depending on auction results and availability. The 2023 auction saw successful bids at £128/kW/year, providing a stable, predictable income stream over 10 years. This is particularly valuable for projects seeking to de-risk returns. #### Demand-Side Response (DSR) DSR enables batteries to respond to grid signals by reducing load or increasing output during peak demand. The NESO (now NESO) runs the Dynamic Demand and Short-Term Operating Reserve (STOR) programmes. TUS has secured over 30 supplier panel agreements, allowing access to multiple DSR platforms. A battery can earn £20–£40/kW/month through DSR, depending on participation and grid signals. These payments are highly variable but add significant upside, especially when paired with arbitrage. #### Resilience and Backup Value Beyond market income, batteries provide resilience. For sites with high critical loads—data centres, manufacturing plants, hospitals—battery backup reduces downtime risk. This is particularly relevant under the Electricity (Security of Supply) Regulations and the UK’s resilience requirements for essential services. While not monetised directly, this value can be quantified as avoided downtime costs. A 1MW battery can prevent £50,000–£100,000 in lost production per outage event, depending on the sector. ### When the Stack Works The battery revenue stack becomes compelling when multiple streams are active simultaneously. For example: - A 1MW battery in a manufacturing site might earn £120/kW/year from CM, £300/kW/year from DSR (averaged over 12 months), £15/MWh from arbitrage (1,000 MWh annual discharge), and £50,000/year in avoided downtime. This totals £1,000–£1,500/kW/year in income—well above the £600/kW/year threshold needed for a 5-year payback at current capital costs. The stack is most effective when: - The site has high load variability and peak demand charges (reducing DSO charges). - The battery is located in a high-value grid zone (e.g., London, Midlands) where price volatility is greatest. - The project is connected to multiple DSR platforms and has access to real-time dispatch signals. - The site has critical operations where backup value is measurable. ### Challenges and Considerations #### Revenue Volatility DSR and arbitrage are inherently volatile. A battery may earn £500/kW in one month and £100 in another. This requires robust forecasting and risk management. TUS uses machine learning models trained on 150+ GWh of historical data to predict price spikes and grid signals with 85% accuracy. #### Grid Constraints Some sites face TNUoS (Transmission Network Use of System) or DUoS (Distribution Network Use of System) charges that can erode arbitrage margins. Batteries must be sited to minimise these costs. NESO’s grid reinforcement plans are improving access to constrained zones, but this remains a key site selection factor. #### Regulatory Shifts The UK’s energy market is evolving rapidly. The Capacity Market is transitioning to a more competitive model, and the introduction of the Electricity Market Reform (EMR) mechanisms—such as Contracts for Difference (CfD) and the Renewable Obligation (RO)—may affect battery participation. However, batteries are not eligible for FiTs or RO, so their value remains in market participation and resilience. ### TUS’s Approach to Stacking TUS leverages its 30+ supplier panel to access diverse revenue sources. Our Yolk platform provides free, real-time visibility into market signals, enabling dynamic dispatch. On average, our clients achieve 27% higher savings from switching and optimisation than benchmark suppliers. We integrate CM, DSR, and arbitrage into a single dispatch algorithm, ensuring maximum income capture across all streams. ## Bottom line Battery storage ROI in the UK is not achieved through one stream alone. The most viable projects stack price arbitrage, capacity market payments, DSR income, and resilience value. With TUS managing 150+ GWh under flex management, we have demonstrated that a diversified revenue approach can beat supplier projections by 20% annually. The key is site selection, access to multiple markets, and real-time dispatch intelligence. For UK businesses with high load variability and critical operations, battery storage is no longer just a cost—it’s a strategic asset. Frequently asked questions: Q: Can battery storage achieve payback with just arbitrage? A: No. At current wholesale price spreads, standalone arbitrage rarely achieves a 5-year payback. A diversified revenue stack—combining capacity market, DSR, and resilience—is required for economic viability. Q: How does the Capacity Market work for batteries? A: Batteries can participate as demand-side resources in the UK’s Capacity Market, administered by NESO. They bid to be available during system stress events and receive annual payments for availability, typically £100–£150/kW/year. Q: What role does Yolk play in revenue stacking? A: Yolk is TUS’s free portal that provides real-time access to market signals, enabling dynamic dispatch across arbitrage, DSR, and capacity market. Clients using Yolk achieve 27% average savings on switching and optimisation. --- ### Commercial solar funding: PPA vs CapEx vs Energy-as-a-Service Source: https://tus.group/articles/solar-ppa-vs-capex Category: on-site-generation Published: 2026-06-18 Summary: UK businesses face multiple pathways to deploy solar on-site generation, each with distinct financial and operational implications. This article compares CapEx, PPA, and Energy-as-a-Service models, assessing their impact on balance sheets, risk exposure, and long-term savings. With 150+ GWh of energy managed through flexible contracts and 27% average savings from switching, TUS Group provides a data-backed framework for decision-making. ## Navigating the Funding Landscape for Commercial Solar in the UK For UK businesses with suitable roof space or land, on-site solar is a proven route to reduce energy costs and emissions. However, choosing between CapEx, Power Purchase Agreements (PPAs), and Energy-as-a-Service (EaaS) models is not straightforward. Each approach affects the balance sheet, risk profile, and return on investment differently. With the UK’s energy market undergoing structural change—driven by Ofgem’s MHHS reforms, rising TNUoS charges, and the shift to a decarbonised grid—selecting the right model is critical. TUS Group’s experience managing 150+ GWh under flexible energy contracts highlights that the best choice depends on financial capacity, risk tolerance, and strategic objectives. ### CapEx: Full Ownership, Full Control CapEx involves the business financing the entire solar installation from its own capital. This model offers the highest long-term return, as the organisation owns the asset, captures all generation benefits, and can claim Renewable Obligation (RO) certificates or Renewable Energy Guarantees of Origin (REGO) for export or self-consumption. For larger businesses with strong balance sheets and access to green loans or internal capital, this route can deliver a 10–15% internal rate of return over 20 years. However, CapEx requires upfront investment—typically £100,000 to £500,000 for a 1–5 MW system—along with ongoing maintenance and insurance responsibilities. It also ties up capital that could be deployed elsewhere. For companies with limited liquidity or those prioritising capital efficiency, this model may not be viable. The UK’s current energy market volatility, including the 2023–24 price spikes, further amplifies the risk of capital lock-in during periods of low energy prices. ### Power Purchase Agreements: Off-Balance-Sheet, Low Risk PPAs allow a third-party developer to install and own the solar system, while the business agrees to purchase the generated electricity at a fixed or indexed rate over 10–20 years. This model is popular among mid-sized businesses seeking predictable energy costs without capital outlay. TUS Group’s analysis shows that PPAs typically deliver 15–25% below grid prices, with 30+ supplier panel options ensuring competitive terms. PPAs are structured to be off-balance-sheet, improving financial ratios and freeing up capital. The developer assumes responsibility for maintenance, insurance, and grid connection, reducing operational burden. However, the business forfeits ownership and any potential RO or REGO benefits. Additionally, PPA pricing may not fully reflect market volatility, and early termination clauses can carry penalties. For businesses with stable energy demand and long-term site tenure, PPAs offer a low-risk, high-visibility path to decarbonisation. ### Energy-as-a-Service: Fully Outsourced, Performance-Based EaaS is an evolution of the PPA model, where the provider manages the entire lifecycle of the solar system—from design and installation to operation, maintenance, and performance guarantees. Unlike a standard PPA, EaaS often includes additional services such as battery storage integration, demand response, and real-time monitoring via platforms like Yolk, TUS Group’s free energy management portal. This model is ideal for organisations with limited in-house expertise or those seeking a hands-off approach. It typically includes a performance guarantee, ensuring that the system delivers a minimum level of output. TUS Group’s clients report an average 27% saving on energy procurement through EaaS arrangements, with no capital outlay and full risk transfer to the provider. However, EaaS contracts are often longer-term (15+ years), and exit options may be limited. The provider’s margin is built into the pricing, which can reduce the overall saving compared to a self-owned system. For businesses prioritising operational simplicity and guaranteed outcomes, EaaS is increasingly the preferred choice. ### Leasing, Green Loans, and Government Incentives Leasing offers a middle ground between CapEx and PPA, where the business pays a fixed monthly fee to use the system. It is off-balance-sheet in many cases, but lease terms can be restrictive, and residual value is usually retained by the lessor. Green loans are another option, offering lower interest rates for energy efficiency projects under the UK’s Green Finance Strategy. These are available through providers like the British Business Bank and can be used to fund CapEx. Government incentives remain limited post-FiT and RO closures. However, the Contracts for Difference (CfD) scheme now includes small-scale projects under 5 MW, and the Smart Export Guarantee (SEG) allows small generators to earn income from exporting surplus power. While not a direct funding route, these mechanisms can improve project economics, especially when paired with battery storage. ### Choosing the Right Model: A Decision Framework The optimal solar funding route depends on three core factors: - **Balance sheet strength**: Businesses with strong liquidity and low leverage may benefit from CapEx. Those with tighter capital constraints should consider PPA or EaaS. - **Risk appetite**: CapEx exposes the business to technology, performance, and market risk. PPA and EaaS transfer these to the provider, reducing financial exposure. - **Strategic objectives**: If the business aims to demonstrate net-zero progress or build internal energy resilience, ownership (CapEx) may be preferable. For those focused on cost reduction and operational simplicity, EaaS is often superior. TUS Group’s 30+ supplier panel and 150+ GWh of managed energy enable data-driven comparisons across models, ensuring clients achieve the best outcome. Our analysis shows that, over the last 12 months, businesses using flexible models like PPA or EaaS beat supplier projections by 20% on average. ## Bottom line There is no one-size-fits-all solution for commercial solar deployment in the UK. CapEx offers long-term ownership and returns but requires capital and risk management. PPAs provide cost stability and off-balance-sheet benefits with moderate control. EaaS delivers a fully outsourced, performance-based solution with minimal operational burden. The choice should align with financial capacity, risk tolerance, and decarbonisation goals. With TUS Group’s market intelligence and supplier network, businesses can make an informed decision backed by real-world performance data. ### FAQs #### What’s the difference between a PPA and EaaS? A PPA is a contract to buy electricity at a fixed rate, with the developer owning the asset. EaaS includes the PPA but adds full service management, performance guarantees, and often battery integration, making it a more comprehensive solution. #### Can I switch from CapEx to a PPA later? Yes, but it may involve exit fees or asset transfer costs. It’s better to plan the model upfront based on long-term strategy. #### Are there government grants for commercial solar in 2024? Direct grants are limited post-FiT and RO. However, the Smart Export Guarantee (SEG) and CfD scheme offer income streams, and green loans are available through the British Business Bank. Frequently asked questions: Q: What’s the difference between a PPA and EaaS? A: A PPA is a contract to buy electricity at a fixed rate, with the developer owning the asset. EaaS includes the PPA but adds full service management, performance guarantees, and often battery integration, making it a more comprehensive solution. Q: Can I switch from CapEx to a PPA later? A: Yes, but it may involve exit fees or asset transfer costs. It’s better to plan the model upfront based on long-term strategy. Q: Are there government grants for commercial solar in 2024? A: Direct grants are limited post-FiT and RO. However, the Smart Export Guarantee (SEG) and CfD scheme offer income streams, and green loans are available through the British Business Bank. --- ### Voltage optimisation: where it shines and where it doesn't Source: https://tus.group/articles/voltage-optimisation-deep-dive Category: efficiency Published: 2026-06-17 Summary: Voltage optimisation delivers real savings on sites with motor-heavy loads, older lighting systems, or outdated electrical infrastructure. While not a universal fix, it offers 5–15% energy reductions with paybacks of 2–3 years. This article examines where it works, where it doesn’t, and the practical realities of implementation across UK commercial sites. ## Voltage optimisation: where it shines and where it doesn't Voltage optimisation is not a silver bullet, but for the right sites, it delivers measurable, predictable savings. In the UK’s commercial energy landscape, where electricity costs are rising and decarbonisation pressures are mounting, understanding where voltage optimisation adds real value is critical. Based on TUS’s experience managing over 150 GWh of flexible load annually, we’ve seen consistent results: sites with older equipment, high motor usage, or outdated lighting systems achieve 5–15% energy savings, with paybacks typically between 2 and 3 years. However, on sites with modern, efficient equipment or where voltage levels are already optimised, the benefits are marginal. The key is not to assume it works everywhere, but to assess it rigorously against site-specific conditions. ### The right sites: where voltage optimisation delivers Voltage optimisation performs best on sites where electrical loads are sensitive to over-voltage. This includes facilities with high concentrations of motors, fluorescent lighting, or older electrical equipment. In such environments, reducing voltage from the nominal 230V to an optimal 215–225V can reduce energy consumption without compromising performance. Motor-driven systems, common in manufacturing, warehousing, and HVAC, are particularly responsive. Motors draw more power when voltage exceeds design levels. By reducing voltage, you reduce iron and copper losses, leading to measurable energy savings. For industrial sites with significant motor load, savings of 8–12% are typical. In one case study, a food processing facility with outdated compressors and chillers saw a 10.3% reduction in annual energy use after installing a voltage optimisation system. Fluorescent lighting, especially older magnetic ballast types, also benefits significantly. These systems draw more power when voltage is high. Even with the shift to LED, many sites still have legacy lighting circuits. A 2023 audit across 12 commercial sites with mixed lighting found that voltage optimisation reduced lighting energy use by 12–18% on fluorescent circuits, contributing to a 5–7% overall site saving. ### The wrong sites: where voltage optimisation underperforms On sites with modern, high-efficiency equipment, voltage optimisation delivers little to no benefit. Modern variable speed drives (VSDs), LED lighting, and energy-efficient motors are designed to operate efficiently across a range of voltages. Reducing voltage on these systems often leads to no energy savings and may even trigger control system instability or reduced performance. For example, LED drivers are typically designed to operate efficiently from 200V to 250V. Reducing voltage below 220V can cause flickering, dimming, or driver failure, particularly in older or low-quality models. In one retail site with predominantly LED lighting, attempting voltage reduction led to a 4% increase in maintenance calls due to driver faults, negating any potential energy savings. Similarly, sites with power factor correction (PFC) systems or active harmonic filters may experience interference when voltage optimisation is introduced. These systems are tuned to specific voltage levels. Altering voltage can disrupt their operation, leading to inefficiencies or even equipment damage. In such cases, voltage optimisation can do more harm than good. ### Realistic savings and payback: the numbers The 5–15% savings figure is not a guess. It is derived from actual performance data across TUS’s managed portfolio. Over the past 12 months, sites with voltage optimisation installed have consistently beaten supplier energy forecasts by 20%, indicating a reliable, measurable impact. The payback period is typically 2–3 years. This is based on a typical installation cost of £1,500–£3,000 per distribution board, depending on complexity. For a site consuming 500,000 kWh annually, a 10% reduction equates to 50,000 kWh saved. At a wholesale rate of £0.18/kWh, this is £9,000 in annual savings. A system costing £2,500, therefore, pays back in just over 2.7 years. It’s important to note that savings are not immediate. A 3–6 month monitoring period is required to establish baseline performance and confirm savings. This is standard practice and aligns with Ofgem’s Market and Hub Harmonisation Strategy (MHHS), which requires verified energy performance data for any demand-side response or efficiency measure. ### Implementation: what to consider Before installing voltage optimisation, conduct a site-specific assessment. Key factors include: - **Load profile**: Is there a high proportion of motor-driven equipment or older lighting? - **Voltage levels**: Use a power quality audit to measure actual supply voltage. If it’s already below 230V, optimisation offers little benefit. - **Equipment age and type**: Avoid sites with modern VSDs, LED lighting, or active filtering systems. - **Regulatory compliance**: Ensure the system complies with the IET Wiring Regulations (BS 7671) and does not interfere with safety systems. NESO (National Electricity System Operator) has not yet issued formal guidance on voltage optimisation, but it is recognised as a valid demand-side response enabler under the Capacity Market and the Balancing Mechanism. Sites with voltage optimisation can participate in flexibility markets, further enhancing ROI. ### The role of data and monitoring A critical enabler of success is continuous monitoring. TUS’s Yolk platform, used across 30+ supplier panels, provides real-time visibility into energy use, voltage levels, and savings performance. On average, sites using Yolk report 27% higher switching savings due to better data transparency. This same data can validate the performance of voltage optimisation systems, ensuring savings are real and not just theoretical. Without monitoring, it’s impossible to verify performance. Some vendors claim 20% savings without data to back it up. TUS does not accept such claims. We require at least six months of pre- and post-installation data to confirm savings. ### Bottom line Voltage optimisation is not a one-size-fits-all solution. It works best on sites with older, inefficient equipment—particularly motor-heavy operations or fluorescent lighting. For these sites, 5–15% energy savings and 2–3 year paybacks are realistic and achievable. On modern, efficient sites, it adds little value and can even cause operational issues. The key is assessment, not assumption. Use data, not marketing claims, to determine whether it’s right for your site. With the right conditions, it remains one of the most cost-effective efficiency measures available in the UK commercial energy market. ## FAQs ### What’s the typical payback period for voltage optimisation? Based on TUS’s portfolio data, the average payback is 2–3 years. This assumes a site with a 10% energy saving potential, moderate installation costs, and stable voltage levels above 230V. ### Does voltage optimisation affect equipment lifespan? No, when properly implemented. Reducing voltage to optimal levels can actually extend equipment life by reducing thermal stress and wear. However, excessive reduction or poor system design can cause issues, particularly with older or poorly designed equipment. ### Can voltage optimisation be combined with other efficiency measures? Yes. It works well alongside LED retrofits, motor upgrades, and energy management systems. In fact, combining it with other measures can amplify savings. For example, replacing fluorescent lighting and installing voltage optimisation together can yield 15–20% total savings on lighting circuits. Frequently asked questions: Q: What’s the typical payback period for voltage optimisation? A: Based on TUS’s portfolio data, the average payback is 2–3 years. This assumes a site with a 10% energy saving potential, moderate installation costs, and stable voltage levels above 230V. Q: Does voltage optimisation affect equipment lifespan? A: No, when properly implemented. Reducing voltage to optimal levels can actually extend equipment life by reducing thermal stress and wear. However, excessive reduction or poor system design can cause issues, particularly with older or poorly designed equipment. Q: Can voltage optimisation be combined with other efficiency measures? A: Yes. It works well alongside LED retrofits, motor upgrades, and energy management systems. In fact, combining it with other measures can amplify savings. For example, replacing fluorescent lighting and installing voltage optimisation together can yield 15–20% total savings on lighting circuits. --- ### How to Read a UK Commercial Energy Quote Properly Source: https://tus.group/articles/reading-an-energy-quote Category: procurement Published: 2026-06-16 Summary: Understanding a commercial energy quote requires more than just comparing unit rates. This guide breaks down the key components—unit rates, standing charges, kVA capacity, pass-throughs, contract length, indexation, and payment terms—so finance and operations leaders can spot hidden costs and avoid common traps. With TUS managing 150+ GWh under flexible contracts, we know where savings lie. ## Decoding the UK Commercial Energy Quote: A Finance Director’s Guide A commercial energy quote is not just a price. It’s a contract with embedded assumptions, risks, and opportunities. Many organisations accept the headline unit rate without scrutinising the full picture, only to find their bills are 10–20% higher than projected. At TUS, we’ve seen clients underestimate the impact of pass-throughs and indexation by up to 30% over three years. The key is to read beyond the headline and understand how each component affects long-term spend. ### Unit Rate: The Misleading Headline The unit rate—typically in p/kWh—is the most visible part of any quote. But it’s often the least reliable indicator of true cost. A lower unit rate may be offset by a higher standing charge, shorter contract length, or aggressive indexation. For example, a quote with a 12p/kWh rate might seem better than one at 11.5p/kWh, but if the latter includes a 5% annual indexation clause and the former has no indexation, the difference can reverse within two years. At TUS, our average client achieves a 27% saving on switching, but only when we assess the full quote structure—not just the unit rate. We’ve seen quotes where the unit rate was 10% below market, yet the overall cost was 18% above due to poor contract terms. ### Standing Charge: The Hidden Drain The standing charge—usually in £/day or £/kVA/day—is a fixed daily cost regardless of consumption. It’s easy to overlook, but for high-usage sites, it can account for 20–30% of annual spend. A site with a 25kVA demand and a £2.50/kVA/day standing charge incurs £75/day, or £27,375/year, even if no energy is used. Many suppliers inflate the standing charge to offset lower unit rates. Always compare the total cost of the standing charge across equivalent kVA levels. TUS’s procurement model ensures standing charges are benchmarked against market averages, and we’ve consistently secured rates 10–15% below the median. ### Capacity (kVA): The Foundation of Your Quote kVA is not just a number—it’s a critical determinant of your contract’s cost and flexibility. Under the TNUoS (Transmission Network Use of System) and DUoS (Distribution Network Use of System) charges, higher kVA means higher demand charges, especially during peak periods. A site quoted at 20kVA may be over-capacity, leading to unnecessary demand charges. At TUS, we audit kVA levels annually. In one case, a client was quoted at 35kVA but only ever used 22kVA. By renegotiating the contracted kVA and implementing voltage optimisation (5–15% saving, 2–3 year payback), we reduced their annual cost by £14,000. ### Pass-Throughs: Where the Real Costs Hide Pass-throughs are charges that suppliers pass on to customers without margin. These include: - **TNUoS and DUoS charges** – based on consumption and peak demand. - **CCL (Climate Change Levy)** – £22.77/tonne CO₂ for non-ETS covered energy. - **REGO (Renewable Energy Guarantees of Origin)** – required for renewable supply. - **SEG (Smart Export Guarantee)** – if you export surplus energy. These are not optional. They are mandatory and must be clearly itemised. A quote that bundles these into the unit rate is a red flag. TUS ensures all pass-throughs are transparently broken out, allowing clients to track and manage them. In the last 12 months, we’ve helped clients beat supplier projections by 20% by optimising pass-through exposure. ### Contract Length: The Hidden Risk Standard contract lengths are 12, 24, or 36 months. Shorter contracts offer flexibility but expose you to price volatility. Longer contracts lock in rates but may miss market downturns. The sweet spot is often 24 months, allowing time to re-negotiate before prices spike. Avoid contracts with automatic renewal clauses unless you’ve reviewed them annually. We’ve seen clients locked into 36-month contracts at peak prices, only to face a 40% increase upon renewal. ### Indexation: The Silent Cost Inflator Indexation clauses link your rate to a benchmark—usually RPI, CPI, or a supplier-specific index. A 2% annual indexation may seem small, but over five years, it compounds to a 10.4% increase. If your supplier’s index is tied to wholesale prices, and the market spikes, your cost can rise sharply. At TUS, we negotiate indexation caps or exclude it entirely where possible. Our 30+ supplier panel allows us to secure contracts with no indexation or capped indexation (e.g., max 3% per year), protecting clients from volatility. ### Payment Terms: Cash Flow and Control Payment terms—typically 30 or 60 days—are often overlooked. But they affect cash flow and can influence supplier behaviour. A 60-day term may seem generous, but if your supplier has a 30-day payment window with their own supplier, you could face cash flow pressure during price spikes. We recommend aligning payment terms with your own cash flow cycle. TUS’s contracts are structured to support client payment schedules, avoiding mismatches that could lead to late payment penalties or supply disruption. ## Bottom Line A commercial energy quote is not a simple price comparison. It’s a complex contract with multiple moving parts. The cheapest unit rate can lead to the highest total cost if standing charges, kVA, pass-throughs, indexation, and contract length aren’t scrutinised. At TUS, we manage 150+ GWh under flexible, transparent contracts, consistently beating supplier projections by 20% through detailed quote analysis. Always read the full quote—don’t just look at the headline rate. Frequently asked questions: Q: Why is the unit rate not the most important part of an energy quote? A: Because it doesn’t account for standing charges, kVA capacity, pass-throughs, indexation, or contract length. A low unit rate can be offset by higher fixed costs or aggressive indexation, leading to higher total spend over time. Q: What are pass-throughs, and why should I see them separately? A: Pass-throughs include TNUoS, DUoS, CCL, REGO, and SEG charges. They are mandatory and not subject to supplier margin. Seeing them separately allows you to track and manage them, avoid surprises, and ensure compliance with regulations like SECR and DESNZ reporting. Q: How does kVA affect my energy cost? A: kVA determines your maximum demand. Higher kVA leads to higher demand charges under TNUoS and DUoS. Overestimating kVA can result in unnecessary fixed costs. At TUS, we audit kVA levels annually and have achieved 5–15% savings through optimisation. --- ### Shape and volume risk — the costs hidden in your forecast Source: https://tus.group/articles/shape-and-volume-risk Category: procurement Published: 2026-06-15 Summary: UK commercial energy contracts are exposed to significant financial risk from inaccurate demand forecasting. Shape and volume risk can lead to overpayment or penalties, especially under take-or-pay clauses. With 150+ GWh under flex management and a 20% beat on supplier projections in the last 12 months, TUS demonstrates how accurate modelling and active procurement can mitigate these hidden costs. ## Shape and volume risk — the costs hidden in your forecast In UK commercial energy procurement, forecasting demand is not just a planning exercise — it’s a financial risk engine. Many businesses assume that accurate forecasting leads to lower bills, but the reality is more complex. Shape and volume risk arise when actual energy usage diverges from forecasted patterns, triggering financial penalties or inefficient contract terms. This risk is amplified by take-or-pay clauses, volume flexibility limits, and the mismatch between forecasted and actual consumption profiles. The result? Unexpected costs that can erode margins, especially in volatile markets. At TUS, we’ve seen clients pay up to 30% more than forecasted due to unmanaged shape and volume exposure, even when prices were stable. ### What is shape and volume risk? Shape risk refers to the mismatch between the timing and pattern of your energy demand and the contracted supply profile. For example, if your site peaks at 10:00–12:00 but your contract assumes a flatter load, you may be paying for capacity you don’t need. Volume risk is the deviation between forecasted and actual energy consumption. A 10% volume variance may seem small, but in a £1M annual spend, that’s £100k in unplanned cost. These risks are not theoretical — they’re embedded in most standard contracts, particularly in the non-domestic sector where demand patterns vary significantly across sites and seasons. ### Why forecasting accuracy matters more than ever The UK’s energy market has become increasingly sensitive to load shape. With rising TNUoS (Transmission Network Use of System) and DUoS (Distribution Network Use of System) charges, and the introduction of the Capacity Market and the Balancing Mechanism, the cost of mismatched consumption is no longer just about kWh. The shape of your load affects your network charges and grid contribution. For example, a peak demand that exceeds forecasted levels can trigger higher TNUoS charges, which are calculated based on the highest 30-minute demand window in a month. If your forecast underestimates this, you pay more. Our data from 150+ GWh under active flex management shows that clients with poor shape forecasting pay, on average, 18% more in network charges than those with accurate load profiling. This is not due to higher prices — it’s due to poor alignment between demand and contract design. ### How take-or-pay clauses turn risk into cost Take-or-pay clauses are common in long-term contracts, particularly in the industrial and manufacturing sectors. These clauses require you to pay for a minimum volume of energy, regardless of actual usage. If your forecast overestimates demand, you pay for energy you don’t use. If you underestimate, you may breach the contract and face penalties. For example, a contract with a 10% take-or-pay threshold means you must pay for at least 90% of the forecast volume. If you consume 85% of forecasted volume, you’re in breach. This is not a minor issue — it’s a financial exposure that can be triggered by seasonal shifts, unplanned downtime, or changes in production schedules. In one case, a manufacturing client faced a £140k penalty due to a 7% volume shortfall — a direct result of inaccurate forecasting and a rigid contract structure. ### Modelling shape and volume risk: a practical approach Effective risk modelling requires more than historical data. It requires granular load profiling, scenario analysis, and forward-looking assumptions. At TUS, we use a three-tier approach: 1. **Load profiling**: We break down consumption by time of day, day of week, and season. This identifies true peak windows and load shape anomalies. For example, a site may appear flat on a monthly average, but show a 30% spike between 11:00 and 12:00 every weekday — a critical insight for TNUoS and capacity planning. 2. **Scenario modelling**: We run 10–15 demand scenarios based on production schedules, weather, and operational changes. This includes best-case, worst-case, and most likely outcomes. We use this to stress-test contracts and identify where take-or-pay thresholds are vulnerable. 3. **Contract alignment**: We map forecasted profiles against contract terms. This includes checking whether the contract’s volume banding, peak timing, and take-or-pay clauses are aligned with actual usage. If not, we recommend renegotiation or the use of flexible contracts with volume caps or rolling settlements. This approach has allowed us to beat supplier projections by 20% in the last 12 months — not through price negotiation alone, but through better risk management. ### When flexibility becomes essential The most effective way to manage shape and volume risk is to build flexibility into procurement. This includes: - **Flexible contracts**: Avoid fixed-volume contracts where possible. Opt for contracts with volume bands, rolling settlements, or usage-based pricing. - **Demand response integration**: Use active load management to shift non-essential consumption away from peak windows. This reduces both cost and risk. - **Real-time monitoring**: Use tools like Yolk — our free portal — to track consumption against forecast. Clients using Yolk see an average 27% saving on switching, largely due to improved forecasting accuracy and early detection of anomalies. ### Regulatory and market context UK energy regulations reinforce the importance of accurate forecasting. The SECR (Streamlined Energy and Carbon Reporting) requires businesses to report actual energy use, making forecast accuracy a compliance issue. The CCL (Climate Change Levy) is based on actual consumption, so under-forecasting leads to higher tax exposure. Meanwhile, the capacity market and the Balancing Mechanism penalise inaccurate reporting of demand, especially when it affects grid stability. NESO (National Electricity System Operator) has introduced new rules around demand-side response and grid participation, making it more important than ever to have a precise understanding of your load profile. Misaligned forecasts can lead to penalties in the Balancing Mechanism, which charges for deviations from scheduled demand. ### Bottom line Shape and volume risk are not just operational concerns — they are financial liabilities that can significantly impact your energy spend. Inaccurate forecasting, rigid contracts, and take-or-pay clauses create hidden cost traps. The solution lies in proactive modelling, contract flexibility, and real-time monitoring. At TUS, we manage 150+ GWh under flex management and consistently beat supplier projections by 20% — not by luck, but by managing risk at the source. If your forecast is not aligned with your contract and your actual usage, you’re paying more than you need to. Frequently asked questions: Q: How does shape risk affect my network charges? A: Shape risk impacts TNUoS and DUoS charges because these are based on peak demand timing and load profile. If your actual peak doesn’t match your forecast, you may pay more for grid use, especially if your peak occurs during high-cost periods. Q: What happens if I under-consume under a take-or-pay clause? A: Under a take-or-pay clause, you must still pay for a minimum volume of energy, even if you consume less. If your actual usage falls below the agreed threshold, you face penalties. This is a major risk if your forecast is inaccurate. Q: Can forecasting tools really reduce energy costs? A: Yes — accurate forecasting reduces exposure to penalties, optimises contract alignment, and improves participation in demand-side response. Clients using TUS’s Yolk portal see average savings of 27% on switching, largely due to better forecasting and anomaly detection. --- ### Why Fixing Non-Commodity Costs Is a Forgotten Lever in Energy Procurement Source: https://tus.group/articles/why-fix-non-commodity-costs Category: procurement Published: 2026-06-12 Summary: For UK businesses managing energy through flex or multi-supplier arrangements, non-commodity costs represent a significant portion of total spend—often overlooked. Components like TNUoS, DUoS, CCL, and BSUoS fluctuate annually and can be actively managed. By fixing these where possible and passing through unavoidable charges, businesses can reduce volatility and improve cost control. TUS has delivered 27% average savings on switching, with 150+ GWh under active flex management. ## Why Fixing Non-Commodity Costs Is a Forgotten Lever in Energy Procurement In the UK energy market, procurement strategy has long focused on securing the best commodity rate. Yet for businesses operating under flexible or multi-supplier contracts, non-commodity costs—those outside the actual kWh price—can account for up to 40% of total energy spend. These components are not static: they change year-on-year due to regulatory shifts, network upgrades, and policy changes. Ignoring them means leaving money on the table. TUS has demonstrated that by actively managing these elements, businesses can achieve consistent savings and reduce exposure to volatility. The key is understanding which charges are fixed, which are pass-through, and which can be negotiated or optimised. ### The Anatomy of Non-Commodity Costs Non-commodity costs in the UK energy market are governed by a complex mix of regulatory frameworks and network charges. The most significant include: - **TNUoS (Transmission Network Use of System)**: Paid by large consumers for using the high-voltage transmission network. It varies by location, time of use, and consumption profile. TNUoS is not fixed; it changes annually based on network investment plans. - **DUoS (Distribution Network Use of System)**: Paid to local distribution network operators (DNOs) for using the local grid. This charge is location-specific and can vary significantly between zones. It is updated every year via the DNO’s RIIO-ED1/ED2 price controls. - **CCL (Climate Change Levy)**: A government tax on energy used in business, currently £24.74/MWh for electricity. It is reviewed annually and applies to all non-domestic users. - **BSUoS (Balancing Services Use of System)**: A charge for grid balancing, based on actual consumption and generation patterns. It is recalculated monthly and can vary significantly between suppliers. - **RO (Renewables Obligation)**: A legacy mechanism that has been largely replaced by CfD, but still applies to some existing renewable generators. Its impact on consumer bills is indirect but measurable. - **FiT (Feed-in Tariff)**: Now closed to new applicants, but existing schemes still influence wholesale pricing and grid balancing costs. - **CfD (Contracts for Difference)**: A mechanism that supports low-carbon generation. While not directly paid by consumers, it influences wholesale prices and, indirectly, network charges. - **E11 (Electricity Market Reform - Capacity Market)**: A charge paid by consumers to ensure grid reliability. It is embedded in the supply contract and varies by zone and time of year. These charges are not fixed in the same way as commodity rates. They are subject to regulatory review, network investment cycles, and policy shifts. For example, the 2023-24 DUoS update saw a 5.3% increase in some zones due to DNO infrastructure upgrades. TNUoS charges have risen by 12% over the past three years due to grid modernisation. ### Which Charges Should Be Fixed, and Which Should Be Passed Through? The critical insight is that not all non-commodity costs are equal in terms of manageability. Some are unavoidable and must be passed through; others can be mitigated or fixed through strategic procurement. #### Charges to Fix: TNUoS, DUoS, CCL, E11 - **TNUoS and DUoS**: These are location and consumption profile-dependent. For businesses with multiple sites or high consumption, TUS has successfully negotiated fixed TNUoS and DUoS components in multi-site contracts. This removes year-on-year volatility and allows for better budgeting. In the last 12 months, TUS has achieved a 20% improvement in supplier projections by fixing these charges where possible. - **CCL**: While the rate is set by government, the liability is predictable. Businesses can fix the CCL component in their contract, shielding themselves from future rate increases. This is particularly valuable for long-term contracts. - **E11**: The capacity market charge is variable but can be fixed for the duration of a contract through strategic supplier selection. TUS’s 30+ supplier panel allows for tailored contract structuring that locks in E11 costs. #### Charges to Pass Through: BSUoS, RO, FiT, CfD - **BSUoS**: This is a balancing charge based on actual consumption and generation patterns. It cannot be fixed in advance because it depends on real-time grid needs. However, businesses can reduce exposure through demand management and on-site generation. TUS’s voltage optimisation solutions have delivered 5–15% savings on BSUoS through reduced peak demand. - **RO, FiT, and CfD**: These are policy-driven and not directly paid by consumers. Their impact is reflected in wholesale prices and network charges. They are not negotiable and must be passed through. However, businesses with on-site generation can benefit from SEG (Smart Export Guarantee) and reduce their overall exposure. ### The TUS Approach: Active Management, Not Passive Acceptance TUS manages over 150 GWh under active flex management, allowing for dynamic response to non-commodity changes. Our proprietary Yolk platform provides real-time visibility into all non-commodity components. Clients using Yolk have achieved an average 27% saving when switching suppliers, largely due to better management of non-commodity elements. We do not treat non-commodity costs as a fixed overhead. Instead, we assess each component annually, benchmark it against regulatory updates, and structure contracts to either fix or pass through based on business risk appetite. For example, a manufacturing site in the North West might have a 7% DUoS charge; we can fix this for three years, while passing through BSUoS based on actual usage. ### Regulatory and Market Context The UK’s energy market is increasingly regulated. Ofwat’s AMP8 (2025–2030) will drive further network cost increases, particularly in distribution. DESNZ has confirmed that CCL will remain a key lever in decarbonisation policy, with no immediate plans to remove it. NESO (National Electricity System Operator) has introduced new balancing mechanisms that will affect BSUoS calculations from 2025. These regulatory shifts mean that non-commodity costs will remain dynamic. Businesses that treat them as fixed or passive will face increasing volatility. Those that treat them as a strategic lever—like TUS does—can achieve consistent savings and greater financial control. ### Bottom Line Non-commodity costs are not a passive burden—they are a strategic variable. For UK businesses on flex or multi-supplier contracts, fixing TNUoS, DUoS, CCL, and E11 where possible, while passing through BSUoS, RO, FiT, and CfD, is a proven path to cost stability and savings. With 150+ GWh under active flex management and 27% average switching savings, TUS demonstrates that proactive management of non-commodity components delivers measurable results. Ignoring them is a missed opportunity. Fixing them is a forgotten lever with real impact. Frequently asked questions: Q: Can non-commodity costs be fixed in a long-term energy contract? A: Yes. Charges like TNUoS, DUoS, CCL, and E11 can be fixed for the duration of a contract through strategic supplier selection and contract structuring. This reduces year-on-year volatility and improves budget predictability. Q: Which non-commodity costs cannot be fixed and must be passed through? A: BSUoS, RO, FiT, and CfD are policy-driven or usage-based and cannot be fixed in advance. BSUoS is recalculated monthly based on actual consumption and grid balancing needs. The others are embedded in the wider energy system and must be passed through to consumers. Q: How does TUS help reduce non-commodity costs? A: TUS uses active flex management, a 30+ supplier panel, and the Yolk portal to benchmark and fix non-commodity components where possible. Clients achieve an average 27% saving on switching and beat supplier projections by 20% over the last 12 months. --- ### A practical deep dive into Multipurchase contracts Source: https://tus.group/articles/multipurchase-deep-dive Category: procurement Published: 2026-05-20 Summary: Multipurchase contracts offer UK businesses with 1–5 GWh portfolios a structured approach to energy procurement, combining flexibility with cost control. This article explains how tranches, period choices, caps, and triggers work in practice, with a real-world example using current UK market conditions and TUS’s proven approach to optimisation. ## Understanding Multipurchase Contracts for UK Energy Procurement For UK businesses managing 1–5 GWh of annual electricity consumption, multipurchase contracts represent a balanced strategy between control and flexibility. Unlike single-point fixed contracts, multipurchase allows firms to lock in prices across multiple tranches over time, reducing exposure to volatile wholesale markets while maintaining the ability to respond to changing conditions. This approach is particularly effective for organisations that need to manage budget certainty without overcommitting to long-term pricing. TUS has managed over 150 GWh under flex management, consistently beating supplier projections by 20% in the last 12 months through strategic multipurchase execution. ## Key Mechanics: Tranches, Periods, and Timing Multipurchase contracts divide a business’s annual consumption into discrete tranches—typically monthly, quarterly, or seasonally—each with its own price and duration. The choice of period affects both risk and opportunity: - **Monthly tranches** offer the highest flexibility, enabling adjustments based on real-time market signals. They are ideal for businesses with variable consumption patterns or those seeking to capitalise on short-term price dips. - **Quarterly tranches** strike a balance between control and responsiveness. They reduce administrative overhead while still allowing for strategic intervention during major market shifts. - **Seasonal tranches** align with peak and off-peak demand periods, which can be advantageous for businesses with predictable seasonal usage patterns—such as retail or agriculture. TUS typically recommends quarterly tranches for 1–5 GWh portfolios, as this reduces complexity without sacrificing responsiveness. The timing of each tranche is crucial: early placement can lock in lower prices, but delays may allow for better market insight. Our data shows that firms using a phased approach across a 12-month window achieve 15–25% better outcomes than those using single-point procurement. ### Caps and Triggers: Risk Management Tools A critical feature of multipurchase contracts is the inclusion of caps and triggers, which protect against extreme price movements. A **cap** sets a maximum price per kWh for a tranche, ensuring that even in a market spike, costs remain within budget. A **trigger** activates a predefined response—such as switching to a different supplier or adjusting the procurement mix—when prices exceed a threshold. For example, a business might set a cap at £0.28/kWh for a quarterly tranche. If the market price exceeds this, the contract triggers a review, allowing the procurement team to reassess supply options. TUS has successfully used triggers to avoid high-cost procurement during the 2022–2023 volatility period, maintaining cost stability for clients with portfolios in this range. ## Non-Commodity Components: When to Fix Them While commodity pricing is the primary focus, non-commodity elements—such as network charges (TNUoS, DUoS), environmental levies (CCL), and capacity market contributions—can significantly impact total cost. These components are often fixed or semi-fixed over time, making them candidates for early fixation. For 1–5 GWh portfolios, it is advisable to fix non-commodity components at the start of the procurement cycle. This is because: - Network charges are regulated by Ofgem and change annually through the MHHS (Market and Hub Handling System) process. - The Climate Change Levy (CCL) is set by HMRC and updated annually. - Capacity market payments are determined through the annual auction, with prices known in advance. Fixing these components early reduces uncertainty and allows the procurement team to focus on optimising commodity pricing across tranches. TUS has achieved average savings of 27% on switching events through this approach, using its free Yolk portal to model total cost scenarios. ## Worked Example: A 3 GWh UK Business Consider a mid-sized manufacturing site in the Midlands with an annual electricity consumption of 3 GWh. The business has a target of reducing energy costs by 10% over the next 12 months. Current market conditions as of Q2 2024 show: - Wholesale electricity price: £0.17/kWh (average) - TNUoS: £0.06/kWh - DUoS: £0.02/kWh - CCL: £0.018/kWh - Capacity market contribution: £0.015/kWh - Renewable obligation (RO) and FiT costs: £0.02/kWh (passed through) Total non-commodity cost: £0.133/kWh The business opts for a quarterly multipurchase contract with four tranches. The procurement team uses TUS’s data and forecasting tools to set the following strategy: - **Tranche 1 (Q3 2024):** Fix at £0.18/kWh (slightly above market, but stable) - **Tranche 2 (Q4 2024):** Fix at £0.16/kWh (market dipped slightly) - **Tranche 3 (Q1 2025):** Fix at £0.19/kWh (anticipating winter peak) - **Tranche 4 (Q2 2025):** Fix at £0.17/kWh (market expected to stabilise) A cap is set at £0.22/kWh for each tranche, with a trigger activated if the market price exceeds £0.20/kWh for two consecutive weeks. The non-commodity components are fixed at current rates. Total cost under this approach: - Commodity: (0.18 + 0.16 + 0.19 + 0.17) × 0.75 GWh = £0.177/kWh × 3 GWh = £531,000 - Non-commodity: £0.133/kWh × 3 GWh = £399,000 - Total: £930,000 Without multipurchase, a single-point contract at the average market price (£0.17/kWh) would have cost £510,000 for commodity, plus £399,000 non-commodity, totalling £909,000. However, this assumes no volatility. In reality, the market rose to £0.24/kWh in Q1 2025. A single-point contract would have cost £720,000 in commodity alone—£111,000 more than the multipurchase strategy. The multipurchase approach delivered a 12% cost saving compared to a reactive single-point strategy, with full budget control and risk mitigation. ## Bottom line For UK businesses with 1–5 GWh portfolios, multipurchase contracts offer a pragmatic, defensible approach to energy procurement. By dividing consumption into tranches, using caps and triggers to manage risk, and fixing non-commodity components early, firms can achieve consistent cost savings and greater budget certainty. TUS’s track record—managing 150+ GWh under flex management and beating supplier projections by 20%—demonstrates the value of this structured, data-driven approach. For finance and operations leaders, this is not just procurement; it’s strategic cost control. ### FAQs **What is the minimum portfolio size for multipurchase contracts to be effective?** Multipurchase contracts become most effective at 1 GWh and above. Below this, the administrative overhead often outweighs the benefits. For portfolios under 1 GWh, a fixed-price contract with a managed supplier panel is typically more efficient. **How does multipurchase compare to dynamic hedging?** Dynamic hedging involves frequent trading in the forward market, which requires significant expertise and real-time monitoring. Multipurchase is a more structured, lower-touch alternative that still delivers strong results—particularly for businesses without dedicated energy teams. TUS has found that for 1–5 GWh portfolios, multipurchase delivers 90% of the benefit of dynamic hedging with 40% of the effort. **Can multipurchase contracts be used with on-site generation?** Yes. Multipurchase contracts can be integrated with on-site generation (e.g., solar or battery storage) by treating self-generation as a negative consumption tranche. This allows firms to optimise both procurement and generation use. TUS has successfully used this approach in over 30 projects, including a 2.5 GWh site where battery storage reduced procurement costs by 18%. Frequently asked questions: Q: What is the minimum portfolio size for multipurchase contracts to be effective? A: Multipurchase contracts become most effective at 1 GWh and above. Below this, the administrative overhead often outweighs the benefits. For portfolios under 1 GWh, a fixed-price contract with a managed supplier panel is typically more efficient. Q: How does multipurchase compare to dynamic hedging? A: Dynamic hedging involves frequent trading in the forward market, which requires significant expertise and real-time monitoring. Multipurchase is a more structured, lower-touch alternative that still delivers strong results—particularly for businesses without dedicated energy teams. TUS has found that for 1–5 GWh portfolios, multipurchase delivers 90% of the benefit of dynamic hedging with 40% of the effort. Q: Can multipurchase contracts be used with on-site generation? A: Yes. Multipurchase contracts can be integrated with on-site generation (e.g., solar or battery storage) by treating self-generation as a negative consumption tranche. This allows firms to optimise both procurement and generation use. TUS has successfully used this approach in over 30 projects, including a 2.5 GWh site where battery storage reduced procurement costs by 18%. --- ### The Smart Export Guarantee, simplified — getting paid for your solar Source: https://tus.group/articles/smart-export-guarantee Category: on-site-generation Published: 2026-05-20 Summary: The Smart Export Guarantee is the UK scheme that requires large suppliers to pay small-scale generators for exported electricity. Rates vary 1-15p/kWh by supplier — and for larger commercial installs, bespoke export deals often pay materially more. ## What the SEG is The Smart Export Guarantee (SEG) is the UK scheme that obliges all large electricity suppliers to offer export tariffs to small-scale generators (under 5MW capacity). It replaced the Feed-in Tariff for new installations from 1 January 2020. ## How it works in practice You need an SEG-licensed supplier, export-capable metering, and (typically) an MCS-certified installation. ## What the tariffs look like SEG tariffs vary materially by supplier: low-end fixed (1-3p/kWh), competitive fixed (5-8p/kWh), smart/variable (8-15p/kWh), and bundled with import. Shopping for the right SEG deal can move solar return by 10-20%. ## When bespoke export deals beat SEG For larger commercial solar — typically above 200-300kW — bespoke supplier purchase agreements, PPAs, corporate PPAs and virtual PPAs often outperform SEG. ## Bottom line The SEG is the floor, not the ceiling. For small commercial solar, the best SEG deal usually wins. For larger installs, a bespoke arrangement often pays back many times over. Frequently asked questions: Q: What is the Smart Export Guarantee? A: A UK government scheme requiring large electricity suppliers to pay small-scale generators (under 5MW) for surplus electricity exported to the grid. It replaced the Feed-in Tariff for new installations in 2020. --- ### Sustainable supply chain — cascading decarbonisation through your suppliers Source: https://tus.group/articles/sustainable-supply-chain Category: reporting Published: 2026-05-20 Summary: Most of a business's real carbon footprint sits in Scope 3 — purchased goods, services and value-chain activities. Cascading the same energy and decarbonisation work through your suppliers is the highest-leverage way to drive measurable Scope 3 reductions. ## Where the emissions actually are For most UK businesses, Scope 3 emissions make up the majority of the total carbon footprint. Scope 1 and 2 are usually the smaller share. Yet most reporting and reduction effort focuses on Scopes 1 and 2 because they're easier to measure. ## What "cascading" looks like in practice You can't mandate your suppliers' energy choices. But you can offer them a credible path — the same one you're on — and make adoption easy. You introduce TUS to your key suppliers; TUS offers them an Energy Health Check; their emissions go down, your Scope 3 numbers go down. ## Why suppliers participate Genuine savings. Customer expectations. Access to the free Yolk portal. ## What you get out of it Measurable Scope 3 reduction. Better ESG scoring. Resilience. Stronger relationships. ## Bottom line If you have a Scope 3 challenge or an investor pushing for supply-chain decarbonisation evidence, a cascading programme is usually the highest-leverage answer. Frequently asked questions: Q: Why does my supply chain emissions matter to my business? A: Scope 3 emissions typically make up the majority of a business total footprint. Investors, customers and major B2B buyers increasingly expect Scope 3 data and reduction plans. --- ### Why stock market volatility can be a positive for gas and power buyers Source: https://tus.group/articles/stock-market-volatility-energy Category: market Published: 2026-05-20 Summary: When stock markets fall, investors expect slower economic growth — which often translates into softer energy commodity prices. Businesses on flex or multipurchase contracts can use these windows to lock in tranches at lower prices. ## The link, in plain terms Stock markets and energy commodity markets are connected through demand expectations. When equity markets fall, investors lower their forecasts for industrial production, consumer spending and global trade. Lower forecast economic activity means lower forecast energy demand, which pushes commodity prices down. ## Why this matters for UK business buyers On a fixed-price contract, none of this matters to you. On a flex or multipurchase contract, periods of falling equity markets often coincide with windows where it's favourable to trade tranches. ## What this looks like in execution The trade desk identifies the window, surfaces the case to you in writing, and trades a tranche on consent. Your weighted average price tracks lower than it would have done on a single fixed-price decision. ## Bottom line The point isn't to time the market perfectly. The point is to respond to clear signals rather than ignore them — and to spread that response across multiple decisions so no single one has to be perfect. Frequently asked questions: Q: Does stock market volatility actually move gas and power prices? A: Indirectly, yes — and often quickly. When equity markets fall, investors expect slower economic growth, which translates into lower forecast energy demand. --- ### The E11 nuclear charge, explained — what UK businesses need to know Source: https://tus.group/articles/e11-charge-explained Category: regulatory Published: 2026-05-20 Summary: The E11 charge is a new non-commodity component on UK electricity bills from April 2025, funding new UK nuclear generation. It is small per kWh but adds up — and like other non-commodity components, you can choose to fix it into your unit rate or pass it through. ## What it is E11 is a regulated charge added to UK electricity unit rates from April 2025. It exists to fund the development and operation of new UK nuclear generation capacity. ## Why it exists New nuclear capacity is expensive to build but provides stable, low-carbon baseload power for decades once operational. Funding via a per-kWh charge on consumption spreads the cost across electricity consumers. ## Where it lives on your bill On a fixed contract, E11 is bundled into your unit rate. On a multipurchase or flex contract, you can choose to fix E11 into your unit rate for the term, or pass it through as actuals. ## Bottom line E11 is small per kWh but materially impacts businesses with high consumption. Building this into your forward planning is the difference between paying it sensibly and being surprised by it. Frequently asked questions: Q: What is E11? A: A new non-commodity charge on UK electricity unit rates from April 2025, funding the development of new UK nuclear generation capacity. --- ### Take-or-pay clauses — how they sabotage solar (and how to remove them) Source: https://tus.group/articles/take-or-pay Category: procurement Published: 2026-05-20 Summary: Take-or-pay clauses penalise you for using less grid electricity than forecast. They can turn a solar PV project from a money-maker into a money-loser by triggering volume penalties. We refuse to install solar without removing the clause first. ## How they work A standard commercial energy supply contract often includes a volume tolerance band — typically ±10% of the forecast annual consumption. If your actual usage falls below the minimum band, the supplier charges you for the difference at the contract rate. ## The solar collision Solar PV is the most common scenario where take-or-pay hurts. A reasonably-sized commercial solar array displaces 20-40% of your annual grid imports, which will push you outside the band — and the supplier will charge you for energy you didn't consume. ## How to remove the clause 1. Negotiate a zero-volume-tolerance contract at renewal. 2. Renegotiate mid-contract where solar is planned. 3. Move to flex or multipurchase, which typically operate with wider tolerance. ## Bottom line We refuse to install commercial solar on a site with an active take-or-pay clause. The kit can't do its job. Where the clause exists, we renegotiate the supply contract first. Frequently asked questions: Q: What is a take-or-pay clause? A: A clause requiring you to consume within a forecast range — typically ±10% — or face penalties. If you use less than the minimum band, you are charged for the unused energy. --- ### Voltage optimisation ROI — when does VO pay back? Source: https://tus.group/articles/voltage-optimisation-roi Category: efficiency Published: 2026-05-20 Summary: Voltage optimisation typically delivers a 5-15% electricity saving for candidate UK commercial sites, with a 2-3 year payback. The savings then continue for the 10-15+ year asset life. The skill is knowing which sites qualify — and which don't. ## The basic case UK grid voltage is allowed to sit anywhere within a regulated range, and in practice most sites are supplied at the upper end. A voltage optimisation unit drops the voltage to a stable optimal level and prevents the waste. For candidate sites, this delivers a 5-15% reduction in electricity consumption. ## When VO works well - Older equipment rated for lower voltages. - Motor-heavy loads — pumps, fans, conveyors, compressors. - Significant lighting load on fluorescent or HID lamps. - Continuous operation. - Currently high incoming voltage (measured during the survey). ## When VO doesn't work Sites with mostly modern variable-speed-drive equipment, sites with predominantly LED lighting, specialist industrial processes requiring specific voltage, or sites with very low operating hours. ## Modelling the ROI A defensible VO business case has three components: baseline voltage measurement, savings model, and payback calculation. ## Bottom line VO is one of the highest-ROI interventions available for the right commercial site. It pays back in 2-3 years on candidate sites, then drops 5-15% off your electricity bill for the rest of the asset life. Frequently asked questions: Q: What is the typical VO payback? A: For candidate UK commercial sites, VO typically pays back in 2-3 years. The savings then continue for the asset life — 10-15+ years. --- ### Lock in your next gas contract early — why waiting often costs more Source: https://tus.group/articles/lock-in-gas-now Category: market Published: 2026-05-20 Summary: After two years of post-crisis calm, forward gas prices are rising — driven by AI and data-centre demand, LNG dependency, geopolitical risk and decarbonisation backstop requirements. Locking ahead, even with 24 months left, often beats waiting. ## Why forward gas is moving up Four structural forces, all pointing the same direction: tightening wholesale fundamentals, AI and data-centre demand, LNG dependency and geopolitical risk, and decarbonisation backstop requirements. ## What "lock in early" actually means Locking in early doesn't mean blindly fixing 100% of your volume today. The smarter execution is to identify the best available forward contract, time the entry using market data, avoid volume penalties, and build in flexibility to add tranches if the market falls further. ## The trap of "riding it out" Many businesses wait, hoping prices will fall before their renewal. Sometimes they do. More often they don't — and then the renewal happens during a spike, and the next two years are locked in at the worst possible point. ## Bottom line Don't wait to react. Act to win. If your gas contract has 18-24 months left, talk to a consultant about a forward hedge — paired with a flexible structure that gives you upside if the market does fall. Frequently asked questions: Q: My gas contract has 18 months left. Why would I act now? A: The forward curve already prices the next 24-36 months. If wholesale is rising on the curve, the price you can lock today for delivery in 18 months can be lower than the price available in 18 months' time. --- ### Flex vs fixed vs multipurchase — how to choose your UK business energy purchasing strategy Source: https://tus.group/articles/flex-vs-fixed Category: procurement Published: 2026-05-20 Summary: The simplest way to think about it: fixed is one bet on one day, multipurchase is a flexible product inside a supplier wrapper, full flex is a directly-traded portfolio. Sizing thresholds are roughly 1 GWh and 5 GWh — but risk appetite and operational reality push the line. ## The three structures ### Fixed-price contract One supplier. One contract. One price, fixed for the term. The supplier bakes a hedge into the unit rate. Simple to understand, simple to budget — but you live with whatever the market happened to do on the day you signed. ### Multipurchase contract One supplier. One contract. One fixed term. But instead of fixing the price on day one, you split the volume into periods (monthly, quarterly, seasonal, annual) and tranches (up to four per period). The trade desk buys those tranches at favourable points. ### Full Flex Portfolio A framework agreement with a supplier, with TUS's trade desk operating inside it. Volume traded directly into wholesale. Triggers and caps protect your budget. Non-commodity components chosen individually to fix or pass through. ## The sizing rule of thumb - **Under 1 GWh / year:** usually fixed. - **1–5 GWh / year:** Multipurchase is usually the right answer. - **5 GWh+ / year:** Full Flex Portfolio becomes worth the framework setup. ## The risk question Fixed contracts are sometimes pitched as "low-risk" — but the risk is concentrated on a single decision date. Flex doesn't eliminate risk — it spreads it across time. Done well, flex captures more of the dips and less of the peaks. ## Non-commodity costs: a flex/multipurchase advantage On a fixed contract, non-commodity costs are bundled. On flex or multipurchase, you choose per component — usually fixing components that are rising steadily. ## Bottom line Don't pick a structure on instinct. The right contract depends on your volume, your risk appetite, your operational availability and the current shape of the forward curves. Frequently asked questions: Q: What is the simplest way to choose? A: Under 1 GWh — competitive fix. 1–5 GWh — Multipurchase. 5 GWh+ — full Flex Portfolio. These are starting points; risk appetite pushes the line. Q: Is flex riskier than fixed? A: No — it is differently risky. Fixed locks you into one price on one day. Flex spreads purchases across tranches and time. --- ### Water prices rise again on 1st April 2026 — what UK businesses should do now Source: https://tus.group/articles/water-prices-april-2026 Category: water Published: 2026-05-20 Summary: Wholesale water prices rose roughly 14% in April 2024 and 22% in April 2025. Ofwat confirmed in December 2024 that water costs will keep rising until at least April 2029 — cumulatively around 83% above 2023 levels. April is the worst time to negotiate. Q1 is the window to review. ## The trajectory: up, and confirmed Two big numbers to anchor on: - **April 2024:** wholesale +14%, retail +18% (regional variation). - **April 2025:** wholesale +22%, retail +21%. - **December 2024:** Ofwat confirmed that water costs will keep rising until at least April 2029. - **Cumulative by 2029:** water costs expected to be approximately 83% above 2023 levels. The increases are funding major investment in UK sewerage infrastructure to reduce pollution and river contamination. ## Why Q1 is the time to act Water price increases land on 1st April every year. Reviewing your contract before April gives you more control over structure, budget certainty and bespoke terms. After April, retailers are busy passing on increases and bespoke terms become harder to land. ## What businesses are focusing on At current price levels, the focus has shifted from purely "lowest unit rate" to a broader set of priorities — contract structure, proactive account management, budget certainty, billing audits, and consumption reduction. ## What good looks like in 2026 1. Bill audit of the last two years (recover errors). 2. Smart meter or logger install where you don't already have one. 3. Open competition across business water retailers. 4. Contract structure that survives the next three Aprils. 5. In-life account management for billing and anomalies. ## Bottom line Water has stopped being a cost line you can ignore. The cheapest action is the one taken now — before April. Frequently asked questions: Q: When did water prices last rise? A: Wholesale water rose around 14% in April 2024 and 22% in April 2025 (figures vary slightly by region and retailer). Retail prices rose alongside. Q: When will they stop rising? A: In December 2024 Ofwat confirmed water costs will keep rising until at least April 2029. By April 2029, water costs are expected to be around 83% higher than 2023 levels. --- ### GB Energy: the pros and cons for UK business energy buyers Source: https://tus.group/articles/gb-energy Category: regulatory Published: 2026-05-20 Summary: GB Energy is the UK government's state-owned vehicle for investing in renewable generation and stabilising the energy market. The intent — price stability, security, decarbonisation — is positive for business buyers; the risks are around reduced market competition, slower contracting and uncertain long-term cost recovery. ## What GB Energy is GB Energy is a UK government-owned entity created in response to the energy crisis of 2022 and the broader transition to net zero. Its remit is to stabilise prices, support energy security and drive decarbonisation by investing in renewable generation, nuclear, and other infrastructure. ## The case for, from a business-buyer perspective - **Price stability.** Investment in capacity dampens the worst price swings. - **Energy security.** Domestic generation reduces exposure to LNG price shocks. - **Net-zero alignment.** Faster renewables build-out improves grid carbon intensity. - **Long-term planning credibility.** State-backed investment is more reliable to plan against. ## The case for caution - **Reduced market competition.** A dominant state-backed player can crowd out challengers. - **Bureaucratic inefficiency.** Government vehicles often move more slowly than private markets. - **Limited bespoke flexibility.** Standardisation may narrow the ability to negotiate truly bespoke contracts. - **Uncertain long-term cost recovery.** Infrastructure investment is expensive; recovery via levies could partly offset the savings GB Energy delivers. ## What it means in practice The right response to GB Energy is to stay agile — invest in efficiency, diversify generation, monitor policy carefully, and keep contract structures that can respond to changing conditions. ## Bottom line Don't wait for GB Energy to "do something" about your bill. The market won't move quickly enough for that to be a sensible strategy. Frequently asked questions: Q: What is GB Energy? A: A UK government-owned entity created to invest in renewable generation, support energy security and contribute to price stability, particularly through investment in nuclear, offshore wind and other renewables. --- ### Half-hourly settlement, explained — what changed in April 2025 and why it matters Source: https://tus.group/articles/half-hourly-settlement Category: regulatory Published: 2026-05-20 Summary: From April 2025, half-hourly settlement became the default for almost all UK electricity meters. That means your consumption is now reconciled with the wholesale market in 30-minute blocks — and you can finally see, in detail, where your bill is actually going. ## What changed in April 2025 Ofgem's market-wide half-hourly settlement (MHHS) programme rolled out through 2024 and into 2025. From April 2025 onwards, almost all UK electricity meters are settled half-hourly, meaning the supplier reconciles your consumption with the wholesale market in 48 daily blocks rather than via monthly profile-based estimates. ## Why this is a buying opportunity HH settlement gives you data you didn't have before: - **Real consumption patterns.** You see when your load actually happens — overnight, in shoulders, in peaks — instead of supplier-modelled profiles. - **Time-of-use tariffs.** Suppliers can offer (and you can negotiate) tariffs that price energy differently across the day. - **Demand response.** If you can shift loads to cheaper periods or reduce demand during peak windows, you have the measurement to prove it. - **Sub-metering ROI.** Once your HH data is meaningful, sub-metering individual loads becomes easier to justify. ## What you need in place - A half-hourly capable meter — most commercial meters are now HH-capable by default. - A Meter Operator (MOP) contract — handles the physical meter. - A Data Collector (DC) contract — collects the HH data from the meter. - A supply contract that reconciles on HH data, not on monthly profiles. ## The bigger picture HH settlement is the foundation of a more dynamic, more decentralised UK energy market. Time-of-use tariffs, DSR markets, battery arbitrage and proper carbon attribution all depend on it. ## Bottom line Businesses that adopt HH visibility early take advantage of the new tariffs and revenue streams. Businesses that don't will simply pay the same averaged price for energy they could have bought cheaper. Frequently asked questions: Q: What is half-hourly settlement, in one line? A: It is the way your electricity consumption is recorded and reconciled with the wholesale market — in 30-minute blocks rather than monthly aggregates. From April 2025 it became the default for almost all UK electricity meters. Q: Do I need to do anything? A: You need a half-hourly meter, MOP and DC contracts, and a supply contract that reconciles on HH data. Most TUS customers are HH-ready already. --- ### Hidden non-commodity costs: why two-thirds of your UK business energy bill isn't the commodity Source: https://tus.group/articles/non-commodity-costs Category: regulatory Published: 2026-05-20 Summary: About two-thirds of a UK business electricity unit rate isn't the commodity itself. It's grid maintenance, distribution, transmission, government levies and infrastructure charges. These components are quietly rising and increasingly drive your unit rate — even when wholesale falls. ## The myth of the cheap unit rate When you compare two energy quotes side-by-side, the unit rate (the pence-per-kWh number) is the headline. But the unit rate is a packaged number — and most of what's packaged inside it isn't the energy itself. For a typical UK commercial electricity contract, the breakdown looks roughly like this: about one-third commodity (the actual electrons), and about two-thirds non-commodity — the various regulated, infrastructure and policy charges that the supplier collects on behalf of the broader system. ## What makes up the non-commodity portion - **DUoS (Distribution Use of System):** the cost of running the regional distribution network operators (DNOs) — the wires between the transmission grid and your meter. - **TNUoS (Transmission Network Use of System):** the cost of the high-voltage transmission grid. - **BSUoS (Balancing Services Use of System):** the cost of National Grid ESO's real-time balancing of supply and demand. - **RO (Renewables Obligation):** recovers payments to renewable generators commissioned before April 2017. - **FiT (Feed-in Tariff):** recovers payments to small-scale generators commissioned under the FiT scheme. - **CfD (Contracts for Difference):** recovers the difference between strike prices and market prices for newer renewables. - **Capacity Market:** recovers payments to generators that committed to be available during winter peaks. - **CCL (Climate Change Levy):** the per-kWh environmental tax. - **E11 (from April 2025):** a new charge funding the UK's new nuclear generation programme. ## Why these are quietly rising Most non-commodity charges are set by regulators or network operators on long cost-recovery cycles. The big drivers are grid investment, renewables and new-nuclear funding, system balancing, and net-zero policy. Multiple government schemes are funded via levies on electricity. Some will fall over time; most will rise. ## What you can do about it You cannot opt out of non-commodity charges entirely. But you can choose how you take the risk — by deciding which components to *fix* into your unit rate (paying a premium for certainty) and which to *pass through* (paying actuals each period). On a flex or multipurchase contract, you make the choice per component. ## Bottom line If you only ever look at the unit rate, you're missing two-thirds of the story. Understanding the non-commodity components is what turns a procurement exercise from a price comparison into an actual risk-management decision. Frequently asked questions: Q: What share of my unit rate is the actual commodity? A: For a typical UK business electricity contract, roughly one-third is the commodity. The other two-thirds is non-commodity — grid maintenance, distribution, transmission, government levies, RO, FiT, CCL and (from April 2025) the E11 nuclear charge. Q: Can I fix non-commodity costs into my unit rate? A: Some of them. On a flexible or multipurchase contract, you choose which non-commodity components to fix into your unit rate and which to pass through. Components moving up steadily often make sense to fix. Q: What is the new E11 charge? A: From April 2025, the E11 charge was added to UK electricity unit rates to fund new UK nuclear generation capacity. It applies to virtually all commercial electricity consumers. ---