Power & Infrastructure Weekly — May 02, 2026

Belgium just halted decommissioning on five reactors and announced a state takeover of its entire nuclear fleet from Engie — the most dramatic European energy reversal since Germany's exit. Meanwhile, FERC locked in a June clock for the rule that will govern every multi-gigawatt data center grid connection in America, and North Carolina dropped a bill requiring data centers to generate 25% of their own clean power on-site. The week's through-line: who owns the baseload risk — governments, utilities, or hyperscalers — has stopped being a theoretical question, and the answers are diverging by jurisdiction in ways that will be hard to unwind.

• Allen BESS Phase 1 (Duke Energy): 50 MW / four-hour lithium-ion battery on the footprint of the retired Allen coal plant, completed under budget and ahead of schedule at roughly $100 million.
• Hussmann A2L Refrigeration Line (Hussmann): First commercial refrigeration systems and merchandisers — rooftop distributed units, condensing units, evaporators, condensers — built around lower-GWP A2L refrigerants.
• Garr & Johnstown North Solar Farms (Neoen): Construction started on 162 MWp and 33 MWp Irish solar projects with single-axis trackers and agrivoltaic site design — nearly doubling the company's Irish capacity.
• Water Reuse Action Plan 2.0 (EPA): Federal framework released April 16 explicitly targeting potable and non-potable reuse to meet rising demand from industry, energy systems, and the technology sector.
• ZutaCore Two-Phase DTC Cooling (Carrier / ZutaCore): Carrier expanded its investment in ZutaCore's closed-loop, two-phase direct-to-chip cooling system, marketed as waterless at the rack level.

Most nuclear policy reversals are slow-motion affairs — years of studies, white papers, political hedging. Belgium's was a press release and an immediate halt order.

On April 30, Belgian Prime Minister Bart De Wever unveiled a deal with Engie to conduct feasibility studies for a full state takeover of the Belgian nuclear fleet and to suspend all decommissioning activities. Only two of Belgium's seven reactors are currently operational — at Doel and Tihange — with operating licenses recently extended until 2035. The other five were shut between 2022 and 2025, and dismantling plans are now suspended. According to Brussels Signal, the takeover will include the entire nuclear fleet, associated personnel, all subsidiaries, and — crucially — all liabilities, including decommissioning obligations.

That last part is the catch. Belgium is buying not just the power plants but the cleanup bill, and no financial terms have been disclosed. The move targets roughly 4 GW of nuclear capacity by 2040, which S&P Global senior analyst Sylvain Cognet-Dauphin told Euronews can only be reached two ways: build new (slow) or restart and extend existing units (faster, cheaper). Independent analysts at Radiant Energy Group estimate Tihange 1 could restart for €350–500 million and deliver power around €65/MWh — roughly a sixth of new-build economics.

What to watch: the October 1 deadline for a binding agreement. If Engie and the government can't agree on price by then, the decommissioning halt becomes legally complicated, and the five offline reactors stay in limbo. The signal isn't Belgium specifically — it's that a European government just decided restart economics beat new-build by a factor of six, and every energy minister on the continent can do the same math.

The most consequential regulatory deadline for data center infrastructure in 2026 now has a firm date — and it's about eight weeks away.

On April 16, FERC committed to action in Docket No. RM26-4-000 by the end of June. Per the Troutman Pepper Locke Washington Energy Report, commission staff have reviewed over 3,500 pages of comments and coordinated across federal agencies, with FERC stating it intends to produce a framework that is "quick, efficient, and legally durable." That last phrase is a tell. As Snell & Wilmer noted, Section 201(b)(1) of the Federal Power Act gives FERC authority over interstate transmission and wholesale sales while reserving retail sales, local distribution, and siting to the states — meaning FERC has historically standardized generator interconnections but not load interconnections.

Two practical wrinkles complicate the picture. First, operators and researchers are demonstrating that data centers need not be inflexible baseload — flexible scheduling can shed tens of MW on grid signals, capturing ancillary revenues while easing transmission stress. Second, every state that has already filed its own large-load tariff (Virginia, California, Colorado) creates potential conflict with whatever FERC produces. The litigation queue is forming before the rule is even written.

What to watch: whether the order sets a specific MW threshold for "large load" treatment, whether it conditions approvals on dynamic load-shedding or VPP capabilities, and whether it addresses on-site co-located generation. That last detail determines whether hyperscalers can bypass the queue entirely. If FERC explicitly preempts state-level tariffs, the five-regime patchwork collapses and Virginia, California, and Colorado have to refile.

If you want a quick read on where grid anxiety is heading, don't look at conference decks. Look at what developers actually file when a queue reopens.

In PJM — the biggest U.S. power market — the answer was natural gas. A lot of it. Utility Dive reported that projects entering PJM's revamped interconnection study process include 106 GW of gas-fired generation. PJM is the market staring hardest at the collision between retiring legacy plants, surging data center demand, and a permitting system where "build fast" remains more slogan than reality. This isn't a press release about an energy transition. It's developers voting with capital and saying: if you need firm capacity soon, this is what gets financed.

The procedural pressure is real. At its April 16 meeting, FERC accepted part of PJM's Order 2023 compliance filing, rejected part, and gave PJM 30 days to refile. PJM also submitted an April 27 tariff filing on load-management performance. Queue reform is colliding with load growth in real time.

What to watch: whether new queue filings assume steady 24/7 baseload profiles or model dynamic curtailment revenues. The answer tells you whether 106 GW of gas is a build plan or an insurance policy. If flexible-load contracting proliferates, some of that gas demand could get deferred or downsized.

Every state that's tried to make data centers pay for their own grid upgrades has done it differently. North Carolina's version adds a requirement no other state has included.

The Ratepayer and Resource Protection Act would require large data centers to pay cost-based electric rates, cover infrastructure expenses tied to their growth, and — the new part — generate at least 25% of their electricity on-site using clean energy. Harrison Fell, a professor of agricultural and resource economics at NC State, told WRAL that "we're looking at demand growth forecasts that are really nothing that we've seen since about the 1950s and 60s" and that "you're basically adding a small city every time you add one of these data centers." Duke Energy has cited data center growth as a key reason it's planning to extend coal plant lives and build new gas generation.

The 25% on-site clean energy mandate is structurally different from Virginia's, Colorado's, and Illinois's approaches. It's essentially a distributed generation mandate embedded in a data center siting law — every large facility becomes part powerhouse, part grid services provider, part thermal utility. Several North Carolina communities have already approved temporary moratoriums on new data centers.

What to watch: whether the 25% on-site requirement survives legislative consideration in the North Carolina General Assembly. If it does, expect projects to either redesign around it or move to states with looser rules and dirtier grids, which would make the emissions outcome worse.

Repurposing coal plant sites for grid-scale storage is becoming a real playbook, not a talking point. Duke Energy just delivered the most concrete example yet.

Duke brought online a 50 MW, four-hour battery system at its former Allen coal plant on Lake Wylie at roughly $100 million, completed under budget and ahead of schedule. Construction begins in May on a second BESS — Duke's largest, at 167 MW / four hours — sited on 10 acres where the coal plant's demolished emissions control system once stood. Both qualify for federal investment tax credits offsetting 40% of cost for Duke customers. A third Allen BESS is proposed in the rate case for 2028.

Part of the economics derives from the site already having transmission interconnection, land, and grid infrastructure — the most expensive and time-consuming pieces of any greenfield BESS project. Allen is becoming a coal-to-storage template that any utility with retiring fossil assets will run through their own spreadsheets. Pair it with CATL's separately announced 60 GWh sodium-ion supply deal with HyperStrong — a procurement-scale commitment to non-lithium chemistry — and the storage stack is broadening on both the siting and chemistry sides simultaneously.

What to watch: whether the ITC survives the current congressional budget process. If it does, expect coal-to-storage filings from every major Southeastern utility. If it doesn't, the math changes fast.

A Belgian prime minister buying back a nuclear cleanup bill nobody fully priced, 106 gigawatts of gas sprinting through a reopened PJM queue like the door might close, and a bill in Raleigh telling Microsoft to bring its own power plant. The grid is no longer asking what we want to build — it's auditing what we already promised, and the math is past due. Onward.

Forward this to whoever signs the interconnection agreements at your shop. They'll want to see what's coming.