Headline insight: Todays AR7 offshore wind auction has locked in very competitive ~£91/MWh CfD prices for energy that is inherently intermittent.​ Once sized to provide quasi‑firm power (e.g. 20 hours/day) using transmission‑scale BESS at today’s UK costs and a 10% real WACC , the incremental cost of storage alone is of the order of £65–70/MWh . That implies an all‑in “firmed” offshore‑wind‑plus‑BESS cost of roughly £155–160/MWh in 2024 prices for 20‑hour availability, and ~£170/MWh for strict 24/7 baseload, before accounting for multi‑day lulls. This is broadly more expensive than new UK nuclear on a firm‑power basis , and well above the bare offshore wind CfD strike price. 1. Today’s Offshore Wind CfD Results (AR7) The AR7 offshore wind auction results announced today can be summarised as follows:​ Total capacity awarded: 8.44 GW offshore wind and floating offshore wind (8.25 GW fixed‑bottom + 0.19 GW floating).​ Strike prices (2024 prices): Fixed‑bottom offshore wind – England & Wales: £91.20/MWh .​ Fixed‑bottom offshore wind – Scotland: £89.49/MWh .​ Blended fixed‑bottom average: £90.91/MWh .​ Floating offshore wind (Erebus, Pentland): £216.49/MWh .​ Examples of large awarded projects: ​ Project Capacity (MW) Region Strike price (2024) Dogger Bank South E 1,500 England £91.20/MWh Dogger Bank South W 1,500 England £91.20/MWh Norfolk Vanguard E 1,545 England £91.20/MWh Norfolk Vanguard W 1,545 England £91.20/MWh Awel y Môr 775 Wales £91.20/MWh Berwick Bank B 1,380 Scotland £89.49/MWh Erebus (floating) 100 Wales £216.49/MWh Pentland (floating) 92.5 Scotland £216.49/MWh Government and industry commentary emphasises that these prices are around 40% below the cost of new CCGT (~£147/MWh) and below current estimates for new nuclear (~£124/MWh) on an LCOE basis, for intermittent output .​ 2. Load Factor Assumptions for AR7 Projects There are three relevant reference points for capacity (load) factors: Historical fleet averages (DESNZ / DUKES): DESNZ long‑term average load factors used for energy statistics: Offshore wind: 38.1% (fleet average).​ CfD methodology assumptions for new build projects: DESNZ’s CfD methodology for delivery years 2027–2031 uses higher net load factors for new offshore wind , reflecting better sites and larger turbines. The methodology table gives:​ Offshore wind (new build): 49% net load factor (mid‑range assumption). Project‑level communications: Dogger Bank and similar next‑generation North Sea projects often cite ~50–55% expected load factors in their own collateral.​ Some Crown Estate/ScotWind developers use a 40.1% fleet average over 2021–23 as a conservative anchor when quoting “homes powered”.​ For the purpose of this exercise: Consider a 40% load factor example , which is a conservative but still realistic long‑run fleet value. DESNZ CfD modelling uses ~49% for new OW, which would slightly improve the storage economics but not change the qualitative picture.​ The calculations below therefore use: Base case: CF=40%CF=40% (conservative, transparent). With commentary on how using 49% would modestly reduce the storage premium. 3. Stylised Storage Model: From 40% Load Factor to 24/7 and 20‑Hour Supply To make the storage maths tractable and transparent, adopt a binary stylised profile : Each MW of offshore wind is either: Generating at full power (1 MW), or Generating nothing (0 MW). The fraction of hours with generation is equal to the load factor c c .For c=0.4 c =0.4, generation occurs 40% of the hours . So, per 1 MW of installed offshore wind: Average daily generation: Eday=c×24×1 MWh=0.4×24=9.6 MWh/day E day= c ×24×1 MWh=0.4×24=9.6 MWh/day. This is the “energy budget” we can distribute across the day using BESS. 3.1 Case 1 – Full 24/7 “Virtual Baseload” from 40% CF Wind Objective: deliver continuous power 24 hours/day from 1 MW of wind, using storage. Let: Pbase P base = constant power delivered to the grid (MW per MW of wind). For energy balance over the day: Pbase×24=Eday=9.6 ⇒Pbase=0.4 MW/MWwind P base×24= E day=9.6 ⇒ P base=0.4 MW/MWwind Under the binary wind model: Hours with generation: Hon=c×24=0.4×24=9.6 h/day H on= c ×24=0.4×24=9.6 h/day Hours without generation: Hoff=24−Hon=14.4 h/day H off=24− H on=14.4 h/day During “on” hours: Generation = 1 MW Demand (to grid) = Pbase=0.4 P base=0.4 MW Surplus for storage = 1−0.4=0.61−0.4=0.6 MW During “off” hours: Generation = 0 MW Demand (to grid) = 0.4 MW Battery must discharge at 0.4 MW Storage sizing per MW of wind: Required discharge power: PBESS=0.4 MW/MWwind P BESS=0.4 MW/MWwind Energy to be stored (daily): Either from charging or discharging perspective: EBESS,24h=PBESS×Hoff=0.4×14.4=5.76 MWh per MWwind E BESS,24h= P BESS× H off=0.4×14.4=5.76 MWh per MWwind Effective storage duration: Duration24h=EBESS,24hPBESS=5.760.4=14.4 hoursDuration24 h = P BESS E BESS,24h=0.45.76=14.4 hours So, in this stylised world, making 40% CF offshore wind into 24/7 baseload requires, per MW of wind : 0.4 MW of BESS power capacity, and 5.76 MWh of BESS energy capacity i.e. a ~14.4‑hour battery . This is already an extreme storage requirement – and it does not address multi‑day lulls, just intra‑day variability. 3.2 Case 2 – “Optimised” High Availability: 20 Hours/Day Firm Supply Now aim for a more realistic target: Deliver constant power for 20 hours/day (e.g. “firm for most of the day”). Allow 4 hours/day where the portfolio is allowed to be short (served by grid or another resource). Using the same binary 40% CF model: Generation hours: Hon=9.6 h/day H on=9.6 h/day Non‑generation hours: Hoff=14.4 h/day H off=14.4 h/day Target firm‑supply hours: Havail=20 h/day H avail=20 h/day Outage (allowed shortage) hours: 24−20=4 h/day24−20=4 h/day To minimise storage: Always serve the load when the wind is blowing (i.e. for 9.6 h/day). Use the battery to extend the supply into an additional 10.4 hours (to reach 20). Leave 4 of the 14.4 non‑generation hours completely unserved by this wind+BESS block. Let Pbase,20h P base,20h be the constant power delivered during those 20 hours. Energy balance: Total load energy per day = Pbase,20h×20 P base,20h×20 This must equal the total wind energy per day (9.6 MWh), so: Pbase,20h×20=9.6⇒Pbase,20h=0.48 MW/MWwind P base,20h×20=9.6⇒ P base,20h=0.48 MW/MWwind Storage balance: Charging: in generation hours, surplus to storage = 1−Pbase,20h=1−0.48=0.52 MW1− P base,20h=1−0.48=0.52 MWEnergy stored = 0.52×9.6=4.99 MWh0.52×9.6=4.99 MWh Discharging: in storage‑served hours (10.4h), discharge at Pbase,20h=0.48 MW P base,20h=0.48 MWEnergy needed = 0.48×10.4=4.99 MWh0.48×10.4=4.99 MWh So per MW of wind: BESS discharge power: PBESS,20h=0.48 MW P BESS,20h=0.48 MW BESS energy capacity: EBESS,20h≈4.99 MWh/MWwind E BESS,20h≈4.99 MWh/MWwind Duration: Duration20h=EBESS,20hPBESS,20h≈4.990.48≈10.4 hoursDuration20 h = P BESS,20h E BESS,20h≈0.484.99≈10.4 hours Comparison: Target BESS power per MW wind BESS energy per MW wind Effective duration 24/7 baseload (40% CF) 0.40 MW 5.76 MWh 14.4 h 20h/day supply (40% CF) 0.48 MW 4.99 MWh 10.4 h So relaxing from 24h to 20h/day still leaves you needing a ~10‑hour battery at nearly 0.5 MW per MW of wind . That’s already “long‑duration” by UK BESS standards (most existing assets are 1–4h).​ 4. Transmission-Scale BESS Costs in the UK (500 MW-class) B ias the BESS capex towards transmission‑system‑scale assets (~500 MW) rather than small distribution projects. Recent UK examples:​ CIP Scotland projects (Coalburn 1&2, Devilla): Each project: 500 MW / 1,000 MWh (2‑hour duration), transmission‑connected.​ Project sponsors state these are “£400 million”‑class investments per 500 MW/1000 MWh unit.​ Implied costs: £400m / 1,000 MWh = £400,000/MWh = £400/kWh £400m / 500 MW = £0.8m/MW Thorpe Marsh & West Burton C (Fidra Energy, National Wealth Fund): Factsheet notes that the “current standard BESS asset in the UK is 100 MW and costs c. £600k per MW” , with Fidra targeting ~£465k per MW for large‑scale assets.​ For a typical 2‑hour 100 MW system, £600k/MW implies: 100 MW costs £60m. If 2h (200 MWh), that’s ~£300,000/MWh = £300/kWh . Global/BNEF benchmarks (headline, not UK‑specific): BloombergNEF’s 2024 survey shows global average turnkey 4‑hour BESS prices around US$165/kWh , with Europe notably more expensive.​ To bias high and focus on transmission‑connected 500 MW‑class systems , a conservative but defensible UK cost assumption today is: Central case: CBESS=£400,000/MWh=£400/kWh C BESS=£400,000/MWh=£400/kWh (aligned with the CIP 500 MW / 1 GWh examples).​ For sensitivity, we can note that at £300,000/MWh (more in line with Fidra’s implied standard asset), results would scale down linearly, but the central story remains the same. 5. Levelising BESS Costs at 10% Real WACC over 20 Years 10% real WACC and 20‑year life (aligned with CfD tenor) to convert capex into a per‑MWh adder: Capital recovery factor (CRF) for r=10% r =10%, n=20 n =20: CRF=r1−(1+r)−n≈0.117CRF=1−(1+ r )− nr ≈0.117 So the annualised cost is approximately 11.7% of capex per year . 5.1 Storage Cost per MW of Offshore Wind Using the 20‑hour case : Per MW of wind: EBESS,20h≈4.99 MWh E BESS,20h≈4.99 MWh Capex per MW wind: CapexBESS,20h=4.99 MWh×£400,000/MWh≈£1.996 millionCapexBESS,20h=4.99 MWh×£400,000/MWh≈£1.996 million Annualised cost per MW wind: ABESS,20h=1.996 m×0.117≈£0.234 m/year A BESS,20h=1.996 m×0.117≈£0.234 m/year Annual energy delivered by the firm block (20 hours/day): In the 20‑hour case, we deliver Pbase,20h=0.48 MW P base,20h=0.48 MW for 20 hours/day: Eyear,load=0.48×20×365≈3,504 MWh/year per MWwind E year,load=0.48×20×365≈3,504 MWh/year per MWwind Levelised incremental cost from BESS alone: ΔPCfD,20h=ABESS,20hEyear,load≈£234,0003,504 MWh≈£67/MWhΔ P CfD,20h= E year,load A BESS,20h≈3,504 MWh£234,000≈£67/MWh So, for 20h/day firm supply , under these assumptions the battery alone adds roughly: ~£65–70/MWh on top of the bare offshore wind CfD price . For the 24/7 case : Capex per MW wind:EBESS,24h=5.76 MWh⇒5.76×£400k=£2.304m E BESS,24h=5.76 MWh⇒5.76×£400 k =£2.304 m Annualised:2.304×0.117≈£0.269m/year2.304×0.117≈£0.269 m / year Delivered firm baseload power is 0.4 MW0.4 MW for 24h/day; annual energy is again 3,504 MWh/year (same total energy output, just spread over 24h rather than 20h). Incremental cost: ΔPCfD,24h≈£269,0003,504≈£77/MWhΔ P CfD,24h≈3,504£269,000≈£77/MWh Summary (given £400k/MWh, 10% WACC, 20‑year life): Case BESS energy per MW wind Capex per MW wind Annualised cost Incremental storage cost (adder) 24/7 baseload 5.76 MWh ~£2.30m ~£269k/yr ~£75–80/MWh 20h/day firm 4.99 MWh ~£2.00m ~£234k/yr ~£65–70/MWh If we instead used £300k/MWh as the unit cost, those adders would fall proportionally to roughly £50–55/MWh (20h) and £57–60/MWh (24/7) . 6. Incremental CfD Price Required vs Today’s AR7 Prices 6.1 Base CfD prices (no storage) From AR7 results:​ Fixed‑bottom offshore wind CfD : England & Wales: £91.20/MWh Scotland: £89.49/MWh Blended: £90.91/MWh These prices buy intermittent energy only. 6.2 Offshore Wind + BESS for 20h/day Firm Supply Add the incremental storage cost: Central case (20h/day, £400k/MWh, 10% WACC): Offshore wind: ~£91/MWh + BESS adder: ~£67/MWh = ~£158/MWh all‑in firm(ish) price in 2024 terms. For strict 24/7 baseload : Offshore wind: ~£91/MWh + BESS adder: ~£77/MWh = ~£168/MWh . These figures ignore: Any system‑service revenues or arbitrage income for the battery (which could offset some cost). Any multi‑day or seasonal storage requirement (which would increase the effective cost of full firming). Network charges, connection costs, and ancillary system costs (again, likely upwards). 6.3 Comparison Against Other Technologies DESNZ’s new cost figures, released alongside AR7, quote levelised costs (LCOE) of approximately:​ New CCGT: ~£147/MWh New nuclear (large): ~£124/MWh On a strictly firm‑power basis, this implies: Offshore wind (intermittent only): Very competitive at ~£91/MWh , well below new gas and slightly below new nuclear. Offshore wind + long‑duration BESS to reach ~20h/day firmness: ~£155–160/MWh central case. Offshore wind + BESS for true 24/7 baseload: ~£170/MWh or higher. In other words, once you pay to firm offshore wind using today’s UK transmission‑scale batteries at a 10% WACC, the all‑in cost rises to the point where it is more expensive than new nuclear per MWh of firm output , and materially above new gas. 7. Sensitivities and Practical Considerations 7.1 Higher Load Factors (e.g. CfD 49%) If we repeat the storage sizing with c=49% c =49% (DESNZ CfD assumption for new offshore):​ The energy budget per MW wind becomes 11.76 MWh/day. Under a similar binary model: 24/7 case requires ~6.0 MWh of storage per MW wind and ~12.2h duration (vs. 5.76/14.4h at 40%). Because both the energy and power scale with CF, the net change in £/MWh adder is modest – the system still needs a large, multi‑hour battery . So using the more optimistic 49% CF improves the economics slightly , but does not change the core conclusion: long‑duration BESS to turn offshore into firm power remains expensive. 7.2 Cost Declines and Lower WACC BNEF and others expect further sharp falls in BESS capex , with global turnkey prices already at ~US$165/kWh on average in 2024, and even US$85/kWh in China.​ If UK transmission‑scale projects converged from £400/kWh to, say, £200/kWh , and WACC fell from 10% to 6% real , the storage adder could plausibly halve , moving into the £30–40/MWh range for 20h/day supply. Even then, the all‑in firmed price would likely still be >£120/MWh when added to offshore wind CfDs. 7.3 Beyond Intra-day Variability The analysis above focuses on a stylised intra‑day pattern with binary generation and no multi‑day droughts. In practice: Wind droughts lasting several days in winter are well‑documented in GB wind statistics.​ Covering those purely with Li‑ion BESS drives storage durations towards multi‑day or even multi‑week , which is economically prohibitive at any plausible BESS cost. System planners expect diversification (geographic spread, interconnection, demand flexibility, other low‑carbon firm sources such as nuclear or CCS) to deal with those events, not BESS alone.​ 8. Implications for SMR’s Comparative Advantage in the UK Putting this together: AR7 confirms that intermittent offshore wind is cheap but not firm. ~£91/MWh CfD for energy that does not run 24/7 .​ Firming offshore with today’s transmission‑scale BESS is expensive at UK costs and 10% WACC. To approach 20 hours/day of firm supply with a 40% CF wind fleet, you need ~10–11h of storage and an incremental £65–70/MWh adder at current UK 500 MW‑class BESS capex.​ All-in “firm offshore wind” costs are above new nuclear and gas on a pure LCOE basis. Wind only: ~£91/MWh Wind + BESS (20h/day): ~£155–160/MWh Wind + BESS (24/7): ~£170/MWh New nuclear: ~£124/MWh; new gas: ~£147/MWh.​ SMR/AMR offers structurally different value: High capacity factor (typically modelled at >90% ), inherently 24/7 , dispatchable within ramp constraints.​ No requirement for massive multi‑hour batteries to convert intermittent output into firm supply. When judged on “firm MWh delivered at the meter” , SMR/AMR economics look much more competitive relative to offshore+storage than if one compares offshore’s bare CfD strike to SMR’s LCOE. For a data‑centre hub: If the requirement is true 24/7 or near‑continuous supply , the system‑cost comparison is not: “Offshore wind at £91/MWh vs SMR at £X/MWh”but rather: “ Offshore wind + firming (BESS, peakers, demand response, interconnectors) vs SMR PPA ”. The stylised numbers above show that, at current UK BESS costs and a 10% real WACC , the incremental CfD uplift required to make offshore wind behave like a quasi‑baseload resource is of the same order (or higher) than the entire offshore wind CfD strike itself . That gap – between intermittent CfD prices and the true cost of firm low‑carbon supply – is precisely where SMRs can make a credible economic case , especially for industrial parks, ports and data‑centre campuses that value 24/7 availability more than marginal £/MWh on a purely intermittent basis.

The British clean energy sector is about to experience a phenomenon not seen since the original dash for gas in the 1990s. As the National Energy System Operator (NESO) prepares to release its final Gate 2 offers by the end of Q1 2026, hundreds of projects—some languishing in limbo for over 18 months—will suddenly transition from purgatory to actionable development status. What follows will be nothing short of a capital market stampede, accompanied by an acute shortage of the experienced consulting services needed to shepherd these projects to financial close. For those of us who work at the interface between utility-scale asset development, commodity agreements, and institutional infrastructure capital, the implications are profound—and the time to prepare is now. The 18-Month Hiatus: Understanding the Backlog The scale of what has been held back is extraordinary. When NESO paused accepting new grid connection applications on 29 January 2025, the connection queue contained approximately 739 GW of capacity — more than six times the UK's peak electricity demand and far exceeding the 200-225 GW of clean generation capacity required by 2030. The previous first-come, first-served system had become hopelessly congested, with some projects facing wait times of up to 15 years.​ The Gate 2 to Whole Queue (G2TWQ) process, which closed its evidence submission window on 26 August 2025, represented a once-in-a-lifetime reordering of the entire electricity transmission connections queue. Over 3,000 transmission-connected projects were required to submit evidence demonstrating their maturity, deliverability, and strategic alignment with Clean Power 2030 objectives.​ The result has been paralysis . Throughout 2025, viable projects with planning consent, secured land rights, and willing investors have been unable to progress because they lacked certainty on connection timing. As Pinsent Masons observed, "the well-publicised delays to the Gate 2 process have shifted M&A transactions to the later part of 2025 and those delays are set to have a real impact on the deliverability of certain protected projects—with developers struggling to raise capital in time to progress their developments and make material financial commitments".​ This enforced waiting period has created an enormous backlog of projects that are ready to move—but have been frozen in place by regulatory uncertainty. The Q1 2026 Inflection Point According to NESO's revised timeline published on 1 October 2025, Gate 1 offers for all qualifying projects will be issued by the end of Q1 2026. Gate 2 offers for customers connecting up to 2030 will follow by the end of Q2 2026 , with offers for post-2030 connections arriving by Q3 2026. The submission window for new applications is also expected to open in Q1 2026.​ NESO and the Distribution Network Operators (DNOs) will begin communicating directly with successful applicants from December 2025, prioritising those protected projects scheduled to connect in 2026 and 2027. This staggered release will create a cascading wave of projects suddenly emerging from the queue with confirmed connection dates, revised commercial terms, and—critically—the certainty that lenders and investors require.​ The potential impact is transformative. Ofgem estimates that connections reform could unlock £40 billion in annual economic growth and eliminate unnecessary grid reinforcements worth £5 billion in future billpayer charges. For individual projects, the transition from uncertain queue position to confirmed Gate 2 offer will fundamentally alter their risk profile—and their financing prospects.​ The Dash for Capital: Convergent Demand in a Constrained Market When hundreds of projects simultaneously receive the green light to proceed, they will all require the same thing: capital. This convergent demand will create unprecedented competition for the finite pool of infrastructure investment available in the UK market. The numbers are daunting. The Government's Clean Power 2030 Action Plan requires approximately £50 billion of investment annually through to 2030. The National Energy System Operator has advised that achieving clean power targets necessitates maintaining "a stable and attractive investment environment" capable of securing over £40 billion of investment annually. Yet even before the queue release, the market was straining to deploy capital at this scale.​ Battery energy storage projects illustrate the challenge. In 2025 to date, approximately 1,405 MW of new battery storage capacity has been commissioned, already surpassing the 2024 total of 1,249 MW. Between April and June 2025 alone, over 100 planning applications were submitted representing 8.4 GW of storage capacity—more than double the same quarter in 2024. The UK Government estimates that 23-27 GW of storage will be required by 2030, up from just 6 GW today.​ When Gate 2 offers begin flowing in Q1 2026, this already-stretched market will face a surge of shovel-ready projects competing for the same institutional capital, the same debt facilities, and the same power purchase agreements. Projects that secured queue positions years ago—but were forced to wait—will suddenly discover that their competitive advantage lies not in timing, but in their ability to move fastest through the development cycle. The winners will be those who have used the 18-month hiatus productively: completing due diligence, securing planning variations, finalising land agreements, and pre-negotiating financing terms subject only to connection confirmation. The losers will be those who assumed the queue release would bring orderly, sequential access to capital markets. The Consulting Bottleneck: When Everyone Needs Help Simultaneously Perhaps the most severe constraint will be access to experienced consulting services. The clean energy sector is already grappling with what the Engineering Construction Industry Training Board describes as an "inadequate" provision of green skills. Eighty-one percent of employers in the renewables sector are already struggling to recruit, and the workforce is expected to grow by 18% over the next three years.​ The Government's Clean Energy Jobs Plan projects that employment in clean energy will double from 440,000 to 860,000 jobs by the end of the decade. An estimated 200,000 additional workers will be needed by 2030 to meet the demands of the green economy. Yet around 20% of the existing workforce is expected to retire by 2030, leaving only 216,000 transferable workers to help address the shortfall.​ For consulting services specifically—the technical advisers, financial modellers, commercial negotiators, and development managers essential to reaching financial close—the bottleneck will be acute. These are not roles that can be quickly filled by graduate recruitment or retraining programmes. They require years of transactional experience, sector-specific knowledge, and established relationships with lenders, offtakers, and regulators. When several hundred projects simultaneously require: Technical due diligence for lender satisfaction Financial modelling for investment committee approval Commercial structuring for power purchase agreements Grid connection negotiation for revised terms Planning variation support for design changes accumulated during the hiatus Development management for the sprint to construction commencement The demand will far exceed supply. Developers who have not already secured relationships with experienced advisory teams will find themselves in bidding wars for scarce consulting capacity—or facing delays that see competitors reach financial close first. The M&A Dimension: A Buyer's Market Emerges The connections reform is also reshaping the renewable energy M&A landscape. As Pinsent Masons noted, "the number of projects in the market perceived as 'de-risked' once a clear notification or Gate 2 offer is received will likely result in more projects than there are investors in the market, and we anticipate a clear shift into buyer-led processes over the next 12 months".​ This represents a fundamental market transition. During the hiatus, development rights with uncertain connection dates traded at substantial discounts to intrinsic value. Buyers demanded contingent payments and consideration adjustments to protect against queue risk. Sellers accepted these terms because the alternative—holding assets through an indeterminate waiting period—consumed capital and management bandwidth without generating returns.​ Post-release, the calculus changes. Projects with confirmed Gate 2 offers will command premium valuations. Those without will face existential questions about their place in the reformed queue—and their prospects for ever reaching financial close. The market will bifurcate sharply between investable assets and stranded development positions. For developers who have navigated the hiatus successfully, the Q1 2026 release creates a window to crystallise value. But realising that value requires the ability to execute transactions quickly, professionally, and at scale. Again, the constraint becomes access to experienced advisory services—M&A advisers, legal counsel, tax specialists—who understand both the technical complexities of the reformed connection regime and the commercial expectations of infrastructure investors. The Supply Chain Crunch: Competition Beyond Capital The dash for capital will be accompanied by a parallel dash for supply chain capacity. The UK already faces "significant backlogs and/or price increases for certain components, often driven by international demand and competition". Equipment lead times for transformers, switchgear, and battery systems have extended substantially since 2022.​ When multiple projects simultaneously attempt to move from financial close to construction commencement, they will compete for the same equipment, the same installation contractors, and the same grid outages for connection works. Projects that have not already secured equipment reservations or installation slots will face delays that push delivery dates beyond connection milestones—triggering penalties or, in extreme cases, termination of connection agreements. The Government has recognised this challenge. The £300 million Great British Energy commitment for offshore wind supply chains aims to "boost domestic jobs, mobilise additional private investment, and secure manufacturing facilities for critical clean energy supply chains". But supply chain capacity cannot be created overnight, and the Q1 2026 release will test every link in the development chain.​ Strategic Implications: Preparing for the Storm For CM Energy Insight's clients—developers, investors, and corporate energy buyers navigating this landscape—several strategic imperatives emerge. First, secure advisory relationships now. The time to engage experienced development managers, technical advisers, and financial modellers is before the queue release, not after. Firms that wait until Q1 2026 to begin assembling their project teams will find themselves at the back of a very long queue for consulting capacity. Second, complete preparatory workstreams during the hiatus. Projects that reach the queue release with updated financial models, refreshed planning consents, and pre-negotiated financing terms will move to financial close far faster than those requiring months of additional work. The 18-month delay should have been used to de-risk every aspect of project delivery that does not depend on connection certainty. Third, understand the reformed commercial framework. The Gate 2 offers will include revised connection terms that may differ significantly from original agreements. Understanding the implications—for project economics, for financing structures, for offtake arrangements—requires technical and commercial expertise that many development teams lack in-house. Fourth, position for supply chain access. Equipment reservations, installation contractor frameworks, and grid outage bookings should be secured as early as possible. The constraint on project delivery will increasingly be physical rather than financial—and first movers will enjoy substantial advantages. Fifth, consider portfolio strategy. Developers holding multiple projects should assess which to prioritise for immediate development and which might be better realised through sale. In a buyer's market, timing and presentation will determine value. Projects brought to market with comprehensive data rooms, clear development pathways, and secured advisory support will command premiums; those offered as-is will attract distressed pricing. Conclusion: A Defining Moment for the Sector The Q1 2026 connection queue release will be a defining moment for the UK clean energy sector. Projects that have waited years for certainty will finally receive it. Capital that has been sitting on the sidelines will finally deploy. Supply chains that have been operating below capacity will finally face full order books. But the transition will not be orderly. When hundreds of projects simultaneously become investable, the market mechanisms designed to allocate capital, services, and supply chain capacity will be severely tested. Winners will be determined not by queue position, but by preparation, relationships, and execution capability. At CM Energy Insight, we have spent the hiatus period preparing for exactly this moment. Our understanding of how to move from need statement to physical solution, from commodity agreement to financial model, from development capital to financial investment decision—this is what the market will require at unprecedented scale. The storm is coming. The question is not whether you will be affected, but whether you will be ready. CM Energy Insight provides management consultancy, interim and project management, and NED support to renewable energy investment businesses throughout their lifecycle. For advisory services on navigating the post-queue release environment, contact our team.

The UK's electricity market stands at a defining moment. A confluence of regulatory reforms, abandoned policy pathways, and the emergence of a wholly state-owned energy company has created a landscape that is at once promising and perilously uncertain for investors in dispatchable generation assets. For those engaged in utility-scale asset development and infrastructure capital deployment, like CM Energy Insight, understanding these intersecting forces is not merely academic—it is essential to informed decision-making. The Capacity Market's Evolution: A Second Price Cap Emerges The Capacity Market has been the cornerstone of Great Britain's security of supply strategy since 2014, ensuring that sufficient electricity generation capacity remains available to meet peak demand. Yet the mechanism has reached an inflection point. The current price cap of £75/kW/year —unchanged in nominal terms since the scheme's inception—has declined by approximately 30% in real terms over the past decade. This erosion has effectively priced out investment in new Combined Cycle Gas Turbine (CCGT) projects, the very assets designed to provide sustained output during prolonged periods of tight supply.​ The Government's October 2025 consultation proposes a fundamental restructuring through the introduction of a Multiple Price Capacity Market (MPCM) . Under this new framework, a second, higher price cap would be introduced specifically for new-build "dispatchable enduring capacity" —assets capable of generating power over extended periods without the duration limitations of battery storage. Existing capacity and short-duration assets would continue competing under the current £75/kW/year ceiling, whilst eligible new CCGTs and similar technologies could access enhanced payments if required to meet system adequacy targets.​ This dual-track approach attempts to solve a critical problem: the T-4 auctions have consistently cleared at or above £60/kW for three consecutive years, yet no new large-scale CCGTs have successfully secured contracts because clearing prices remain insufficient to underwrite the capital-intensive construction of these facilities. The Government acknowledges that without intervention, older thermal assets—including nuclear and biomass units—may retire without adequate replacement capacity to backstop an increasingly renewables-dominated system.​ REMA's Resolution: Reformed National Pricing Prevails Perhaps the most consequential decision affecting investment confidence came in July 2025 when the Department for Energy Security and Net Zero published the outcome of its Review of Electricity Market Arrangements (REMA). After years of uncertainty that had cast a shadow over investment decisions, zonal pricing was definitively ruled out .​ The Government concluded that tolerating the inefficiencies of a reformed national pricing system strikes a better balance than accepting the risks of wholesale market fragmentation. Industry had warned repeatedly that zonal pricing would create "unnecessarily high instability and uncertainty around future prices and zonal boundaries"—precisely the conditions that drive up the cost of capital and deter the patient institutional investment that infrastructure development requires.​ The decision to retain a single GB-wide wholesale market, whilst introducing a package of reforms including the Strategic Spatial Energy Plan (SSEP), represents an evolutionary rather than revolutionary approach. The SSEP, due for delivery by the end of 2026 , will spatially optimise the energy system across Great Britain, identifying optimal locations, quantities, and types of electricity infrastructure. This planning-led approach, combined with reforms to Transmission Network Use of System (TNUoS) charges and connection processes, aims to address the geographic mismatch between renewable generation in Scotland and demand centres in England—without fragmenting the market itself.​ For investors, this clarity is invaluable. As Energy UK observed, "Reformed National Pricing provides certainty for businesses across the economy, helping to drive investment and jobs". The alternative—a shift to locational marginal pricing that could not have been implemented until the 2030s—would have introduced seven years of investment uncertainty, putting Clean Power 2030 goals at risk.​ The Paradox of New CCGT Investment Yet even with capacity market reforms on the horizon, the investment case for new gas-fired generation remains profoundly conflicted. The Climate Change Committee has recommended a 2035 phase-out date for unabated gas generation, with requirements that all new units be carbon capture and storage (CCS) or hydrogen-ready by 2025. This creates a temporal conundrum: investors are being invited to commit capital to assets that may face regulatory obsolescence within a decade of commissioning.​ Several significant projects are nonetheless advancing. Uniper is developing the Connah's Quay Low Carbon Power project—a CCGT with integrated carbon capture technology designed to deliver approximately 1.3GW of low-carbon capacity, with the first train targeted for commercial operation before 2030. At Net Zero Teesside, a partnership between BP and Equinor has awarded an £833 million construction contract to Balfour Beatty , with completion expected in 2028. The Killingholme project in Humber is also under development by Uniper, targeting a minimum 470MW capacity.​ What distinguishes these projects is their integration with emerging CCUS infrastructure. The Government's commitment of £21.7 billion to carbon capture—confirmed through the Track 1 and Track 2 cluster sequencing process—provides a pathway for gas-fired generation to continue operating beyond 2035 if emissions can be captured and stored. The HyNet and East Coast Cluster networks are now receiving substantial public backing, with contracts signed and construction imminent.​ The investment calculation thus becomes one of technology optionality: a CCGT built today with CCS-readiness designed in from inception may command a very different risk profile than a conventional unabated plant. The Capacity Market's proposed higher price cap for "dispatchable enduring capacity" appears designed precisely to attract such investment—but questions remain about whether the enhanced economics will prove sufficient given construction cost inflation and the complexity of integrating carbon capture at scale. Great British Energy: A State-Owned Outlier in a Privatised Market Perhaps the most distinctive feature of the current UK energy landscape is the emergence of Great British Energy (GBE)—a 100% publicly owned company established by the Great British Energy Act 2025, which received Royal Assent in May of this year. With an £8.3 billion capitalisation over this Parliament, GBE represents the most significant intervention by the British state in energy markets since privatisation in the 1980s and 1990s.​ The company's mandate is multifaceted: to invest in, develop, and own energy generation infrastructure; to catalyse private sector investment; to strengthen domestic supply chains; and to support local and community energy projects. Crucially, the Act establishes GBE as "operationally independent"—a company with its own CEO and board, distinct from governmental direction in day-to-day operations, yet ultimately accountable to Parliament through annual reporting requirements.​ GBE's CEO, Dan McGrail, has been explicit that the company is "not here to compete, but to catalyse investment". This positioning is strategically important. Unlike EDF in France or Vattenfall in Sweden—state-owned giants that dominate their national markets—GBE's £5.8 billion operational budget (excluding the nuclear allocation) is modest relative to the estimated £200 billion of investment required across the electricity sector by 2037. The intention is not to displace private capital but to de-risk projects at their earliest , most uncertain stages, thereby crowding in institutional investment.​ The first tangible deployments reflect this philosophy. GBE has committed £180 million to install solar panels on schools and hospitals—a low-risk, highly visible investment that demonstrates capability whilst avoiding land-use controversies. The company has also announced £700 million for offshore wind supply chain development, working alongside The Crown Estate and private partners to leverage additional private investment.​ For developers accustomed to a wholly privatised market, GBE's emergence raises important questions . Will state-backed projects receive preferential treatment in grid connections or planning decisions? How will GBE's participation in joint ventures affect the competitive dynamics of asset auctions? And what happens when a publicly owned entity pursues returns alongside, or in competition with, private capital seeking the same opportunities? The Government has set an expectation that GBE will deliver returns on its commercial activities by 2030 and produce a plan for becoming self-financing by that date. This creates inherent tensions: a company mandated to take on early-stage development risk, support communities, and strengthen supply chains must also demonstrate commercial viability. Navigating these objectives will require considerable skill—and may occasionally produce outcomes that disadvantage purely commercial competitors.​ Stability or Instability? Assessing the Investment Environment The aggregate effect of these developments is a market simultaneously more certain and more complex than it was only twelve months ago. The ruling out of zonal pricing removed what many investors considered an existential threat to project economics. The retention of a single national wholesale price provides the predictability that underpins long-term power purchase agreements and debt financing. The proposed capacity market reforms offer a pathway for new dispatchable generation to achieve viable economics—at least in principle.​ Yet significant uncertainties persist. The Government's separate consultation on retrospectively changing the indexation of Renewables Obligation payments from RPI to CPI has provoked fierce criticism from institutional investors. As the Association of Investment Companies warned, "retrospectively changing the terms of existing agreements is a sure-fire way to undermine investor confidence". If the Government is prepared to alter the basis of long-standing contractual arrangements for renewables, what assurance do capacity market participants have that their agreements will not be similarly adjusted?​ The TNUoS reform pathway also remains unclear. Ofgem has indicated that a robust new framework for transmission charging should be in place by 2029, but the intervening years will feature volatility and unpredictability in charges—particularly challenging for projects in Scotland where transmission costs are already elevated. The proposal under CMP444 for a temporary cap and floor on TNUoS charges was not supported by Ofgem, leaving developers to navigate substantial locational cost uncertainty.​ Furthermore, the sheer scale of required investment—around £50 billion annually through to 2030—means that even with policy reforms, competition for capital will be intense. NESO has advised that achieving Clean Power 2030 requires maintaining "a stable and attractive investment environment" capable of securing over £40 billion of investment annually. Against this backdrop, any policy missteps—whether on indexation, grid charging, or market design—could have amplified consequences.​ Implications for Asset Development and Commodity Strategies For those working at the interface between utility-scale new build assets, long-term commodity requirements, and institutional infrastructure capital—the very nexus that CM Energy Insigh t serves—several strategic implications emerge. First, the economics of dispatchable generation are being actively re-engineered . The proposed MPCM framework, if implemented ahead of the 2027 auctions, will fundamentally alter the investment case for new CCGTs. Projects positioned to access the higher price cap will command a significant advantage; those unable to meet eligibility criteria (likely requiring CCS or hydrogen-readiness) may find themselves stranded in the lower-price tier.​ Second, commodity agreements must reflect regulatory uncertainty . Long-term gas supply contracts for power generation assets must now account for the possibility—indeed the likelihood—that unabated gas generation will face increasingly stringent constraints through the 2030s. Hydrogen and carbon capture infrastructure timelines become critical dependencies, and supply agreements should incorporate optionality for fuel switching as these pathways mature. Third, the financial structuring of projects must accommodate a mixed public-private landscape . GBE's participation in joint ventures, its role in de-risking early-stage development, and its mandate to catalyse private investment all create opportunities for innovative capital structures. Developers should consider how GBE partnerships might enhance bankability—whilst remaining attentive to the governance and commercial implications of state involvement. Fourth, the retention of national pricing preserves familiar commercial frameworks —but the reforms to transmission charging and spatial planning will introduce new locational considerations. The SSEP, when published in 2026, will effectively constitute a government-endorsed map of preferred development locations. Assets aligned with SSEP recommendations may benefit from streamlined connections and reduced grid charges; those in less favoured locations may face headwinds. Conclusion: A Market in Transition The UK electricity market is undergoing its most significant transformation since the introduction of NETA in 2001. The capacity market reforms, the REMA resolution, and the establishment of Great British Energy collectively represent a recalibration of the relationship between state and market in ensuring security of supply and achieving decarbonisation. For investors in dispatchable generation, the path forward is neither straightforward nor risk-free. But the fundamental direction is now clearer than at any point in recent years . Zonal pricing will not fragment the market. A mechanism for funding new CCGTs is being constructed. Public capital is entering the market—not to compete, but to catalyse. Whether this combination of reforms produces a stable investment environment or merely reconfigures the sources of instability remains to be seen. What is certain is that the decisions made in the coming months—on price caps, on eligibility criteria, on the terms of GBE's commercial activities—will shape the generation mix that carries Great Britain through the 2030s and beyond. The investors who navigate these crosswinds most successfully will be those who understand not only the technical parameters of market design, but the political economy that shapes it. In an era when energy policy is inseparable from industrial strategy, decarbonisation mandates, and national security considerations, the capacity to interpret regulatory signals and position assets accordingly is not merely advantageous—it is existential. CM Energy Insight works at the interface between utility-scale asset development, long-term commodity agreements, and institutional infrastructure capital. For advisory services on navigating the evolving UK electricity market, contact our team.

November 2025 | CM Energy Insight Britain stands at a critical juncture in its energy transition. The government's Clean Power 2030 target promises energy independence and lower bills through homegrown renewables. Yet beneath the policy rhetoric lies a troubling paradox: the UK imports 20% of its electricity at a cost of £250 million monthly, pays the highest power prices in the developed world, and remains structurally dependent on foreign technology platforms in an era of escalating geopolitical risk. This isn't a failure of ambition—it's a failure of market design. The Wholesale Market's Fatal Flaw Britain's wholesale electricity market operates on marginal pricing: all generators receive the price set by the most expensive plant needed to meet demand. When gas-fired power stations set the price—as they do 97% of the time—even cheap domestic renewables are paid gas rates. This mechanism, a legacy of 1990s liberalisation, was designed for a different era. Today it creates perverse outcomes: windfall profits for renewable operators, elevated costs for consumers, and systematic bias toward imported energy over cheaper domestic sources. The consequences are stark. UK electricity imports hit record highs in 2024 (12.2 TWh imported vs 3 TWh exported), not because Britain lacks generation capacity, but because the market structure makes imported French nuclear or Norwegian hydro more attractive to suppliers than domestic wind or solar constrained by grid bottlenecks. British consumers pay twice: once for the infrastructure, again for the electricity. The Foreign Technology Trap Meanwhile, the UK's energy transition increasingly relies on technology platforms it doesn't control. China dominates over 80% of solar panel manufacturing, controls lithium refining for batteries, and is making aggressive inroads into wind turbine markets. Chinese battery systems—now central to grid balancing—have raised security concerns after Reuters uncovered rogue communication devices in certain inverters, exposing potential cyber vulnerabilities hardwired into critical infrastructure. This dependency echoes Britain's pre-2022 reliance on Russian gas—a strategic error the UK resolved never to repeat, yet seems poised to replicate with Chinese clean energy supply chains. As geopolitical tensions mount, export controls on battery materials could severely disrupt the planned 2030 phase-out of internal combustion vehicles and grid storage deployment. Domestic nuclear offers partial relief but at prohibitive cost and glacial timelines. Small modular reactors remain unproven at commercial scale. Imported LNG, while readily available, perpetuates fossil fuel dependency and exposes Britain to volatile commodity markets. The Missing Political Dimension Recent scholarship by political economist Damon Silvers illuminates why technical solutions alone will fail. Britain's neoliberal integration with European energy markets delivered economic efficiency but imposed change on industrial communities without democratic consent. Brexit's success in formerly industrial constituencies reflected decades of accumulated resentment at restructuring experienced as diktat, not partnership. The energy transition risks repeating this pattern. Communities see Chinese solar farms on agricultural land, battery facilities with opaque ownership, and offshore wind projects benefiting distant shareholders—all while their electricity bills rise. Without genuine stakeholder engagement, technically sound projects become political flashpoints. This connects to deeper historical patterns. As Silvers demonstrates, Britain's post-imperial strategy foundered when racial politics blocked Commonwealth integration in the 1960s, forcing a pivot to Europe that was economically rational but politically fragile. Today's "Global Britain" rhetoric invokes Empire 2.0 nostalgia while immigration policies undermine trade partnerships with former colonies. You cannot demonize a nation's citizens while courting their renewable energy markets. A Path Forward Reform must address three dimensions simultaneously: Market Structure Reform : Implement zonal or nodal pricing to reward domestic generation location, decouple renewable revenues from gas prices (following Spain's successful model), and accelerate grid connections for British projects currently facing 4-6 year delays. Strategic Sovereignty : Urgently develop UK battery cathode manufacturing capacity (companies like Integrals Power have proven pilot-plant capabilities), mandate security audits for all grid-connected storage systems, and structure financing to favor European and allied supply chains despite higher upfront costs. Democratic Legitimacy : Ensure energy transition projects include community benefit agreements, workforce transition plans for displaced fossil fuel workers, and transparent decision-making. Industrial change imposed by market forces alone stores political instability—as Brexit demonstrated. The UK possesses world-class engineering expertise, deep capital markets, and urgent need for energy security. What's missing isn't capability but political will to reform market structures that reward the wrong outcomes and strategic clarity about which dependencies are acceptable in an age of great power competition. The scholars are unanimous on one insight: economic efficiency divorced from political legitimacy is unsustainable. Britain's energy future depends not just on gigawatts deployed but on whether the transition is experienced as done with communities, not to them. CM Energy Insight works at the interface between utility-scale new build assets, long-term commodity agreements, and institutional infrastructure capital. We believe in deploying game-changing capital at disruptive scale into well-structured projects to effect real change.

Investment Opportunities in the UK Energy Sector: A Contrarian Perspective The UK energy landscape is undergoing a seismic shift, driven by regulatory changes, technological advancements, and evolving market dynamics. While mainstream narratives often focus on renewable energy as the only viable investment avenue, this article aims to explore the broader spectrum of investment opportunities within the UK electricity generation, trading, carbon certificates, gas supply, and capital markets. Adopting a contrarian perspective, we will delve into underappreciated segments that may offer significant returns for discerning investors. 1. Electricity Generation: Beyond Renewables While the UK government has set ambitious targets for renewable energy generation, traditional electricity generation methods should not be overlooked. Natural gas , in particular, remains a crucial component of the energy mix as a transitional fuel. Here are some reasons to consider investing in this sector: Reliability of Gas Supply: With the volatility of renewable sources, gas generation provides a reliable backup , ensuring grid stability. Technological Innovations: Advances in e.g. engine efficiency and biomethane are making gas generation cleaner and more sustainable, appealing to environmentally conscious investors. Regulatory Support: Government "capacity market" policies may favor gas as a transitional fuel, providing a safety net for investments in this area. 2. Electricity Trading: Capitalizing on Market Volatility The rise of smart grids and decentralized energy systems has created a fertile ground for electricity trading. Investors can leverage market volatility in several ways: Short-Term Trading Opportunities: The fluctuation in electricity prices due to demand-supply mismatches presents opportunities for short-term traders. Emerging Market Platforms: New trading platforms are emerging that allow for greater participation from smaller investors, democratizing access to this market. Hedging Strategies: Investors can utilize electricity derivatives to hedge against price volatility, enhancing portfolio stability. 3. Carbon Certificates: A Market on the Rise The carbon trading market is projected to grow significantly as countries aim to meet their climate goals. Here’s why investing in carbon certificates could be a lucrative opportunity: Increased Regulatory Pressure: As the UK tightens its emissions targets, the demand for carbon credits will rise, driving up prices. Corporate Sustainability Initiatives: Companies are increasingly investing in carbon offsets to meet sustainability goals, creating a robust market for certificates. Speculation Opportunities: The nascent nature of the carbon market allows for speculative investments, which can yield high returns if timed correctly. 4. Gas Supply: A Contrarian Bet Despite the global push towards renewables, gas supply remains a critical component of the energy infrastructure. Here’s why investors should consider this sector: Energy Security: With geopolitical tensions affecting energy supplies, investing in domestic gas production can enhance energy security. Infrastructure Development: The UK is investing in gas infrastructure, including LNG terminals, which could yield long-term returns. 5. Capital Markets: Financing the Energy Transition Capital markets are evolving to support the energy transition. Here’s how investors can tap into this trend: Green Bonds and ESG Investments: The demand for green financing is surging, providing opportunities for investors in green bonds and ESG-compliant companies. Private Equity and Venture Capital: Investing in startups focused on energy technology can yield high returns as the sector grows. Public Listings of Energy Companies: As energy companies pivot towards sustainability, public listings may offer lucrative investment "exit" and MOIC opportunities. Conclusion While the narrative around UK energy investments often centers on renewables, there are numerous underexplored opportunities in electricity generation, trading, carbon certificates, gas supply, and capital markets. By adopting a contrarian approach, investors can identify lucrative avenues that are poised for growth amidst the ongoing energy transition. As the market evolves, those willing to look beyond conventional wisdom may find themselves at the forefront of a profitable investment landscape.

Q - Should we adopt a more autocratic green energy decision making process here? China's commitment to renewable energy just cranked up another notch, and it's a powerhouse. January saw a flurry of approvals for massive pumped hydropower stations, each boasting over 1 GW of capacity. But one project stands out: a colossal 78 GW renewable energy hybrid complex proposed by SDIC along the Yalong River Basin in Sichuan Province. This ambitious undertaking sets a new precedent for integrated renewable development and highlights China's rapid strides towards a greener future. Let's unpack the significance of this mega-project: Scale Matters: 78 GW is no small feat. This single complex could power nearly 40 million homes in the United States. What's even more astounding is that it represents just a fraction of China's recent renewable additions. Last year alone, the country installed a staggering 100 GW of hybrid wind-solar projects, showcasing its dedication to diversifying its energy mix. Pumped Hydro Powerhouse: This technology acts like a giant battery, storing excess renewable energy generated during low demand periods and releasing it when needed. Its integration with wind and solar ensures a more stable and reliable grid, addressing the intermittency challenges inherent in these resources. SDIC Leads the Charge: The State Development & Investment Corporation is a major player in China's infrastructure development. Its involvement in this project not only signifies the government's support for renewable energy but also reflects the growing collaboration between public and private entities in driving the clean energy transition. Beyond 2035? China's track record in exceeding renewable energy targets is remarkable. With its rapid project development pace, the 2035 completion date for the 78 GW complex might prove conservative. An early completion would not only accelerate China's decarbonization goals but also set a global example for ambitious, integrated renewable energy development. Looking Ahead: This project is just one piece of China's larger renewable energy puzzle. The country aims to peak its carbon emissions before 2030 and achieve carbon neutrality by 2060. Continued advancements in technology, policy support, and financial investment will be crucial to achieving these ambitious targets. The Takeaway: China's commitment to renewable energy is undeniable. The 78 GW SDIC complex is a game-changer, showcasing the country's ambition and capability to integrate diverse renewable resources and push the boundaries of clean energy development. This project serves as a beacon of hope for a future powered by sustainable and reliable energy sources.

Executive Summary: The business world faces constant challenges, demanding agility, resilience, and an unwavering pursuit of excellence. What if the answers lie not in the sterile boardrooms of corporate giants, but in the crucible of elite military units like the SAS? This article explores how lessons learned from special forces can be repurposed, unlocking untapped potential within your organization and propelling you toward global competitiveness. Table of Contents: Lean and Mean: Ideal Team Size Command Structure: Flattening the Hierarchy Decision Agility: Cutting Through Red Tape Forging Mental Steel: Resilience and Tenacity Beyond Desk Chairs: The Value of Physical Fitness Motivating Missions: Rewarding Performance Beyond Paychecks Muscle Memory for Success: Continuous Improvement Lean and Mean: Ideal Team Size Forget bloated corporations. Special forces operate in small, tightly-knit units where every member is cross-trained and adaptable. Mimic this structure. Build smaller, high-performing teams with diverse skillsets. This fosters collaboration, reduces bureaucracy, and empowers individuals, unlocking agility and rapid response to market shifts. Command Structure: Flattening the Hierarchy Rigid hierarchies stifle innovation. Special forces rely on flat structures where information flows freely and decisions are made at the tactical level. Empower your teams. Break down reporting chains. Trust your people to make informed decisions on the ground, fostering ownership and accelerating progress. Decision Agility: Cutting Through Red Tape In combat, hesitation is fatal. Special forces train for adaptability and swift decision-making in dynamic situations. Translate this to your business. Minimize bureaucracy. Create lean approval processes. Encourage calculated risks and empower leaders to act quickly, seizing fleeting opportunities before competitors. Forging Mental Steel: Resilience and Tenacity Elite soldiers face grueling challenges, building unwavering mental resilience. Cultivate this in your team. Encourage calculated risks, embrace failures as learning opportunities, and foster a "never give up" attitude. This mental fortitude equips your people to navigate market turbulence and emerge stronger. Beyond Desk Chairs: The Value of Physical Fitness Physical fitness isn't just about aesthetics. Special forces understand the link between body and mind. Promote employee well-being through fitness initiatives. A healthy team is a sharper, more resilient team, better equipped to handle pressure and think clearly under duress. Motivating Missions: Rewarding Performance Beyond Paychecks Money isn't the only motivator. Special forces understand the power of purpose and shared goals. Define a clear, inspiring mission for your company. Celebrate shared victories. Recognize individual contributions beyond financial incentives. Foster a sense of belonging and purpose, igniting passion and driving performance. Muscle Memory for Success: Continuous Improvement Special forces train relentlessly, honing their skills to perfection. Adopt this ethos. Implement continuous improvement programs. Encourage experimentation, learning from successes and failures. Create a culture of growth and refinement, ensuring your team stays ahead of the curve. The Call to Action: Deploy Your Forces The battlefield of global competition is no place for complacency. By repurposing the lessons of special forces, you can build a lean, agile, and resilient organization primed for victory. Challenge your business as usual. Embrace these tactics. Unleash the full potential of your people and watch your company rise to the top. Remember, in the words of the SAS motto: Who Dares Wins.

Executive Summary: In the adrenaline-fueled world of new energy investing, chasing the next shiny project across borders might seem like the ultimate power move. But hold your horses, global infrastructure cowboys! This scattershot approach to international business development (IBD) is more like setting off firecrackers than building a sustainable empire. Here's why strategic IBD, not opportunistic dabbling, is the key to unlocking true global dominance. Table of Contents: The Allure of the Shiny Object: Why Opportunism Fails Strategic IBD: Planning Your Global Coronation From Fireworks to Foundation: Examples of Good & Bad IBD Conclusion: Stop the Chaos, Start the Conquest The Allure of the Shiny Object: Why Opportunism Fails Let's face it, chasing individual overseas deals can be intoxicating. The allure of quick wins, exotic markets, and first-mover bragging rights (bragga-watts) is undeniable. But here's the harsh truth: without a strategic foundation, these "wins" often turn into pyrrhic victories. Isolated projects lack synergy, struggle with cultural misalignment, and bleed resources that could fuel a cohesive global strategy. Think of it like building a house by buying random bricks on sale – you might end up with a colorful pile, but it won't keep the rain out. Strategic IBD: Planning Your Global Coronation So, how do you avoid the firework fizzle and build a lasting international empire? By embracing strategic IBD. This means: Defining your global ambition: Are you aiming for regional dominance, niche expertise, or a full-blown energy czar crown? Knowing your "why" guides your "where" and "how." Understanding the lay of the land: Conduct thorough market research, analyze cultural nuances, and identify potential partners and pitfalls in each target region. Building a cohesive plan: Develop a roadmap that aligns your international expansion with your overall business goals, resource allocation, and risk tolerance. Think of it as your global GPS, not just a compass pointing to the nearest shiny object. Cultivating talent with global smarts: Invest in people who understand the intricacies of international business, from language fluency to cultural sensitivity. Remember, it's not just about the deals, it's about building bridges. From Fireworks to Foundation: Examples of Good & Bad IBD Exhibit A: The Opportunistic Oopsie: Imagine an energy investor jumping at the chance to build a solar farm in a remote African country, lured by generous subsidies. Sounds good, right? But without considering the complex regulatory environment, the incumbent competitive response, their government alignment, lack of skilled local labor, and fragile grid infrastructure, the project becomes a money pit. Ouch. Exhibit B: The Strategic Masterstroke: Now, picture a company like McDonald's, meticulously adapting its menu, restaurant design, and supply chain to local tastes and customs in each new market. This strategic approach has fueled their global expansion for decades, making them a true king of the burger castle. Conclusion: Stop the Chaos, Start the Conquest The global energy landscape is full of potential, but navigating it requires more than just opportunism. By embracing strategic IBD, you can transform scattered projects into a unified force, laying the foundation for sustainable international dominance. It's time to ditch the firework mentality and start building an empire that stands the test of time. Remember, global chess, not global roulette, is the game for true winners. Disclaimer: This blog article is for informational purposes only and should not be considered as professional advice. Please consult with qualified professionals before making any investment decisions.

Physical Fitness Fuels Business Vitality Daily Focus Triumphs over Trivial Tasks Navigate with Precision: Your Office Maps and Plans Mission Description and Objectives: Your North Star Resource Wisely: Plan, Source, and Utilize Command and Control: Monitor, Feedback, Correct Embrace the Culture of Truth Incentivize Excellence: Milestones and Profitability Rapid Decision-Making: The Catalyst for Success Legacy Thinking: You're as Good as Your Last Role Commandment 1: Physical Fitness Fuels Business Vitality As we embark on this journey of European business expansion, remember that your physical well-being is the foundation of your professional success. Daily runs and a healthy diet not only boost energy levels but also enhance mental clarity, ensuring you're ready to conquer each day with vigor. Commandment 2: Daily Focus Triumphs over Trivial Tasks In a world of constant distractions, prioritize daily focus over scattered activities and drowning in emails. Concentrate on impactful tasks that align with our mission and objectives. Your daily dedication to focused work will propel us towards our goals. Commandment 3: Navigate with Precision: Your Office Maps and Plans Just as a ship needs navigation tools, use the office equivalent of maps and plans to guide us in the right direction. Maintain progress with strategic planning, ensuring every move aligns with our overarching mission. Commandment 4: Mission Description and Objectives: Your North Star Define our mission clearly and set specific objectives. Your understanding of the bigger picture is crucial for the success of our European expansion. Let our mission be your guiding North Star, providing direction and purpose in every decision. Commandment 5: Resource Wisely: Plan, Source, and Utilize Craft a resourcing plan that outlines the sources and uses of resources. Efficient allocation ensures we have what we need, when we need it. Smart resourcing is the key to maintaining momentum in the competitive European business landscape. Commandment 6: Command and Control: Monitor, Feedback, Correct Implement a command and control system to monitor progress. Regular feedback loops allow for quick course correction. Stay vigilant, address challenges promptly, and steer the team towards success with adaptability and precision. Commandment 7: Embrace the Culture of Truth Cultivate a culture where truth reigns supreme. Admit when we're off-plan; only then can corrective action be taken. Open communication fosters a collaborative environment where challenges are met head-on, and success is a shared journey. Commandment 8: Incentivize Excellence: Milestones and Profitability Recognize and reward exceptional performance. Tie incentives to milestones achieved and contribute to the overall profitability of our European ventures. A motivated team propels us forward, celebrating victories and learning from challenges. Commandment 9: Rapid Decision-Making: The Catalyst for Success In the fast-paced world of European business, decisiveness is key. Rapid decision-making ensures we capitalize on opportunities and navigate challenges with agility. Trust your instincts, rely on the team, and make decisions promptly. Commandment 10: Legacy Thinking: You're as Good as Your Last Role Remember, your legacy is shaped by the culmination of your actions. Strive for excellence in every role, project, and decision. You are only as good as your last role; let it be a testament to your commitment, innovation, and unwavering pursuit of success. In the pursuit of business expansion, these commandments are the guiding principles that unite us, drive us, and propel us towards unparalleled success. Embrace each day with the passion and determination required to make our mark in the business landscape. Together, we write the story of triumph and prosperity.

As the Head of New Business Development for Europe, I encounter countless questions concerning the viability of large-scale energy storage projects. With ambitious climate targets and an evolving energy landscape, the need for robust solutions is clearer than ever. Today, I'll focus specifically on why Europe requires Gigawatt-scale (1,000 Megawatt-hour) battery storage projects to overcome critical grid challenges. Table of Contents: Grid Constraints: Balancing Supply and Demand in a Renewable Ecosystem Solar Generation and Demand Timing Mismatch: Bridging the Sunlight Gap Offshore Wind: Capturing Overnight Generation for Daytime Demand Lost Dispatchable Power: Filling the Gap Left by Traditional Sources Slower EV Adoption: Mitigating the Impact on Peak Demand Management 1. Grid Constraints: Balancing Supply and Demand in a Renewable Ecosystem Europe's transition to renewable energy, dominated by solar and wind, poses a unique challenge: these sources are inherently variable and intermittent. While abundant, their production doesn't always align with peak demand periods. Grid constraints, stemming from insufficient transmission capacity and limited flexibility, restrict the seamless integration of these renewables. Gigawatt-scale battery storage acts as a buffer, absorbing excess renewable energy during peak production and releasing it when demand rises, ensuring grid stability and efficient utilization of clean energy. 2. Solar Generation and Demand Timing Mismatch: Bridging the Sunlight Gap Solar energy peaks at midday, often exceeding demand. However, evening demand surges when the sun sets. Without storage, this excess daytime solar goes unused, while traditional, often carbon-intensive, sources are ramped up to meet evening demand. Gigawatt-scale storage bridges this "sunlight gap" by storing surplus solar and releasing it later, reducing reliance on fossil fuels and optimizing renewable energy utilization. 3. Offshore Wind: Capturing Overnight Generation for Daytime Demand Offshore wind offers enormous potential, but its generation pattern often peaks overnight when demand is low. Gigawatt-scale storage captures this abundant overnight wind energy, releasing it during peak daytime demand periods, maximizing the value of this clean resource and reducing reliance on dispatchable power plants. 4. Lost Dispatchable Power: Filling the Gap Left by Traditional Sources Europe is phasing out traditional coal and gas-fired power plants, which previously provided critical grid stability and dispatchability. This creates a gap in readily available, on-demand power. Gigawatt-scale battery storage replicates this dispatchability characteristic, offering fast-responding power reserves upon demand, ensuring grid stability and security during periods of high demand or unexpected outages. 5. Slower than Forecast EV Adoption: Mitigating the Impact on Peak Demand Management While electric vehicle (EV) adoption is crucial for decarbonization, its impact on grid demand is complex. Slower-than-anticipated EV rollout means peak demand spikes might persist longer than previously expected. Gigawatt-scale storage provides the necessary flexibility to manage these potential demand surges, mitigating pressure on the grid and ensuring reliable power delivery even with slower EV adoption. Conclusion: A Timely Opportunity for Gigawatt-Scale Investment Addressing grid constraints, bridging the solar gap, capturing offshore wind potential, replacing dispatchable power, and managing evolving demand all highlight the critical need for large-scale battery storage in Europe. This presents a significant opportunity for private equity funds to invest in a future-proof technology that directly addresses key challenges in the region's energy transition. As a trusted advisor, we stand ready to support your journey into this dynamic and impactful market. Ready to explore the growing potential of gigawatt-scale battery storage in Europe? Contact us today to discuss your investment goals and unlock the power of a sustainable future.

Context The privatisation of the UK electricity generation, transmission, distribution and retail industry in the 1990s serves as a example of what might be constraining the decarbonisation of todays transport, heat, refining and petchem industries, and gives us some ideas for how to bring about accelerated change. Background. It seems like a long time ago now. Back in the late 1980s - early 1990s, the UK Electricity production, distribution & sales industry went through a massive change, driven by the Thatcher government and similar economic theology in Europe and USA. State owned and monopolistic entities, that had served their countries well for decades, were being broken up, in In order to create new markets that would attract and facilitate new business models, new entrants, start ups, and disruptors, all supported by hungry private equity. Textbooks have been written about this journey and whether or not it was successful from the point of view of the industry employee or the taxpayer. But I want to focus on here is what it did for the nature of culture and change management within these companies. The process of disaggregating (or "unbundling") the electricity system created competing organisations in each segment of the marketplace. New generators appeared, and customers were free to change their supplier. This in turn created a requirement for new and competitive business models, with suppliers choosing new fuel sources, new generation technology, new website platforms, new pricing approaches etc. This in turn served to create a competitive work environment. Those employees who could embrace change, think outside the box, and move rapidly were rewarded. And the net benefit for UKPLC was that, by the early 2000s, the cost of electricity in the wholesale market with close to the break even cost or the short run marginal cost, based upon some of the cheapest fuels in the marketplace such as coal. This in turn meant that the UK's manufacturing industry had a huge cost advantage compared to our neighbours. This benefit to the UK Economy is often missed in the debate about whether electricity privatisation was a success or not. The Need for independent private equity in todays stubbornly high fossil carbon industries. They say that necessity is the mother of all invention. And this proves true in the paragraphs above. As privatisation of the electricity sector spread, as new business models emerged, an additional dimension of competitive pressure and opportunity was also being deployed. This was the need to rapidly decarbonise the electricity generation sector and the resulting NFFO, ROC and CFD regimes. The combination of the deregulation of the electricity sector and the competitive forces that created, coupled with the government's agenda to decarbonize, resulted in some dramatic changes in the industry structure, as summarised below Coal fired power stations had to adopt and adapt to cleaner "biomass" fuels and eventually were forced to close New market entrants switched to burning gas as a cleaner fuel and using combined cycle gas turbines as a more efficient and lower cost form of generation New and disruptive business models emerged. Combined heat and power plants meant that electricity was being generated almost as a byproduct of industrial heat production. Power production was being democratised by for example rooftop solar and onshore wind. New sources of capital from non traditional locations were creeping into the market, especially in the offshore wind sector. New international energy companies sort out the UK as a target rich environment. Such companies included Enron, Entergy, AES, Cinergy, AEP, EDF, Statkraft, Vattenfall, RWE and Eon. So why is this relevant to today's broader European industrial decarbonisation agenda? My casual observation is the Is that other (non electricity) sectors such as transportation, oil refining, and petrochemicals have some how managed to sidestep the decarbonisation agenda, with the result that many of the organisations are performing the same business models as they did 70 years ago. This is compared to an electricity sector that looks nothing like it did 30 years ago. Employees in the carbon heavy sectors have remained safe in their jobs for perhaps 30 years. The key question then becomes one of how to incentivize the increasingly rapid change in these industries that still need to decarbonize. Whilst these industries may be very proud of their technical prowess, they do seem to lack the rigour of a private equity owner. And a culture of embracing rapid change to remain globally competitive.