Waldorf Production loses court case for restructuring

 

Waldorf Production UK Plc, Re - Find Case Law - The National Archives

The judgment in Re Waldorf Production UK Plc [2025] EWHC 2181 (Ch) concerns the proposed restructuring plan of Waldorf Production UK Plc (“WPUK”), an oil and gas company operating on the UK Continental Shelf. The plan aimed to enable WPUK to continue trading while pursuing a solvent sale, involving a cross-class cram down of dissenting unsecured creditors—Capricorn Energy and HMRC—who opposed the plan. The restructuring was supported by a steering committee of bondholders holding 84.8% of the bonds. The court examined the statutory preconditions under the Companies Act 2006, including whether dissenting creditors would be worse off under the plan than in the relevant alternative (likely administration or liquidation), and whether the plan was fair.

Justice Hildyard concluded that although the statutory conditions for sanctioning the plan were met, the plan was ultimately unfair. He found that WPUK and its bondholders failed to engage meaningfully with the dissenting creditors during the formulation of the plan, offering only a 5% recovery without negotiation or justification. The court emphasized that the benefits of the restructuring—particularly the potential for a solvent sale—depended on the compromise of the unsecured creditors’ claims. Drawing on recent Court of Appeal decisions, including Re Petrofac, the judge stressed that fairness requires a genuine attempt to negotiate a reasonable compromise with all stakeholders, especially when the restructuring benefits are derived from their concessions.

The judgment also highlighted troubling conduct by WPUK’s former management, including the payment of a US$76 million dividend based on flawed accounts and the failure to engage with HMRC regarding significant tax liabilities. These actions contributed to WPUK’s financial distress and undermined the credibility of the restructuring plan. Ultimately, the court refused to sanction the plan, inviting the parties to pursue further negotiations and potentially return with a revised proposal that fairly allocates the benefits of the restructuring among all creditor classes.

See also: https://oginsights.blogspot.com/2025/07/waldorf-production-north-sea-operator.html

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Permian Part II

The Permian continues to deliver record gas volumes. At the same time, gas demand at the US Gulf Coast continues to grow as more LNG facilities come online.

Yet gas pricing at the Permian remains in negative territory with a $5-7/mcf discount to pricing at Gulf Coast hubs. Egress remains constrained but should ease with pipeline expansions and Matterhorn coming online.

 

Looking forward and further downstream, record LNG exports could see a softer LNG flush market – expect merchant revenues (i.e. excess volumes above contracted SPAs) at Gulf Coast LNG facilities to decline in the coming years.

 

In contrast, pipeline revenues will see growth with pipelines being booked to capacity. Further optionality for pipelines in the case of lower LNG excess volumes trading by supplying existing and new gas power plants in the Gulf Coast region – Texas will be an attractive region for power intensive datacenter development.

 

More generally, the US should see c.2.5% load growth per year over the next 10 years – with 60% driven by datacenters, 40% from reshoring/reindustrialisation and  electrification (20% each). This will need to be met by building new gas generation, renewables (onshore solar), and grid stabilisation with BESS. Coal retirement delays (which kicked off during the Biden administration) will also be needed in a truly “all of the above” solution.

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German onshore FiP award prices decline again

Feed-in Premium (FIP) Mechanism

In Germany, most new large-scale renewable energy installations, including onshore wind, receive support through a sliding Feed-in Premium (FIP), known as the Market Premium (Marktprämienmodell).

The FIP is the difference between the "Reference Value" (the price awarded in the auction) and the "Market Value" (the average market price achieved by the power, adjusted for the specific technology and time of generation).

FIP Payment = Reference Value - Market Value

The producer sells the electricity directly on the market and receives the FIP as a top-up payment.

The "Ceiling" Price

The "ceiling" or maximum price is set by the Bundesnetzagentur (Federal Network Agency) for the auctions.

This is the highest price (in cents per kilowatt-hour, or ct/kWh) that bidders are allowed to submit in the tender.

Ceiling Price (Maximum Bid): For example, the ceiling for onshore wind auctions in 2024 and 2025 was set at 7.35 ct/kWh.

The "Actual" Price (Reference Value):

The "actual" price is the Reference Value/Award Price that a successful project secures in the auction. This is the price that is used to calculate the FIP.

Actual Price (Reference Value): This is the winning bid price, which is generally below the ceiling price.

The Bundesnetzagentur has kept the ceiling stable because the "upward trend in bid volumes has not yet led to a significant decrease in the award prices" (meaning the actual winning bids are still relatively high).

In summary

Ceiling Price: The maximum allowed bid in the onshore wind auctions (e.g., 7.35 ct/kWh for 2024/2025). This price is a cap on the Reference Value.

Actual vs. Ceiling: The actual awarded price (Reference Value) in the auction is typically lower than the ceiling price. The FIP payment is then calculated based on this Actual Award Price minus the actual market revenue.

Results Show Increasing Competition and Decreasing FiP 

Tender Date (Closing)	Maximum Bid Price (Ceiling) (ct/kWh)	Average Volume-Weighted Award Price (Actual) (ct/kWh)	Difference (Actual−Ceiling) (ct/kWh)
Dec 2020	∼6.20 (est.)	5.91	(0.29)
May 2021	6.2	5.91	(0.29)
Sep 2021	6.2	5.79	(0.41)
Feb 2022	6.2	6	(0.20)
May 2022	6.2	6.3	0.10
Sep 2022	6.4	6.34	(0.06)
Feb 2023	7.35	7.3	(0.05)
May 2023	7.35	7.31	(0.04)
Aug 2023	7.35	7.32	(0.03)
Nov 2023	7.35	7.33	(0.02)
Feb 2024	7.35	7.33	(0.02)
May 2024	7.35	7.33	(0.02)
Aug 2024	7.35	7.33	(0.02)
Nov 2024	7.35	7.15	(0.20)
Feb 2025	7.35	7	(0.35)
May 2025	7.35	6.83	(0.52)
Sep 2025	7.35	6.57	(0.78)

Key Trends

• Maximum Bid Price (Ceiling): The ceiling was adjusted upward significantly in 2023 (from $\sim 6.2$ ct/kWh to 7.35 ct/kWh) due to rising costs for construction, financing, and operation. This higher ceiling has been maintained through 2025.

• Near-Ceiling Bids (2023-2024): After the ceiling was raised, the Average Award Price (Actual) came very close to the Maximum Bid Price (Ceiling) for all of 2023 and most of 2024. This indicates that developers needed the full support price to cover their increased costs, leaving very little competitive margin.

• Falling Prices (2025): Starting in late 2024 and continuing into 2025, the Average Award Price began to show a noticeable decline, moving further below the ceiling. This suggests that competitive pressure has increased, likely due to a better project pipeline (more permits) and potentially stabilized or reduced costs, leading to lower subsidy requirements. The auction in September 2025, for example, saw the average bid fall to 6.57 ct/kWh, a significant drop.

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Apollo / RWE JV to fund Amprion

Apollo (NYSE: APO) today announced that Apollo-managed funds and affiliates have agreed to commit €3.2 billion of equity to a newly established joint venture with RWE, Germany’s largest power producer and a global leader in renewable power generation. The JV will be operationally controlled by RWE and hold and fund RWE’s 25.1% stake in Amprion, a Transmission System Operator (TSO) spanning across seven German federal states and serving approximately 29 million people and industrial corporations.

 
The JV will provide the required equity capital for its 25.1% stake to support Amprion’s major investment program for grid expansion over the next decade, enhancing critical German energy infrastructure. The JV is supported by reliable and stable dividend returns from Amprion’s regulated asset base. For RWE, the partnership with Apollo also aligns with its strategy to grow its generation portfolio of renewables, batteries and flexible generation assets and to focus on its core activities of power generation and energy trading.
 
Apollo Partner Jamshid Ehsani said, “This partnership with RWE will help fund long-term capex for critical grid expansion in Germany to power homes and industry, and it underscores our focus on delivering tailored capital solutions to leading global companies and essential infrastructure. It also reflects Apollo’s commitment to strong, lasting partnerships across both the private and public sectors. Looking ahead, we expect to further accelerate our investment activity in Europe, with a particular focus on Germany, France, Italy and the UK.”
 
The JV investment builds on Apollo’s significant record of providing scaled capital solutions to leading companies. Since 2020, Apollo has originated more than $100 billion of bespoke, high-grade solutions, including for European companies and/or European assets such as EDF, BP, Vonovia, Air France-KLM, AB InBev and Intel’s Fab 34 in Ireland, among others. Earlier this year, the Firm announced that it expects to deploy more than $100 billion in Germany alone over the next decade, helping to meet market demand for long-term financing and investments.
 
The transaction is subject to regulatory approvals and customary closing conditions, and it is expected to close in the fourth quarter of 2025. Latham & Watkins LLP and Paul, Weiss, Rifkind, Wharton & Garrison LLP are serving as legal counsel to the Apollo funds.

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Fossil and Renewables Have to Coexist

Five years ago, the narrative became renewables all the time. The perception was that renewables would displace fossil fuels, and that fossil fuels would have no place in the world. That perception has been truly shattered.

With the power demand of AI and electrification, and the impossibility of delivering electricity to meet that demand, the world is rolling back. Hyperscalers are signing power from renewables and fossil power plants - they need and want both.

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PJM: Producer - Pay to Play

 

PJM adopts the common practice of new power producers paying for the grid upgrade required to support the new load being introduced by the producer. This ensures fairness as a principle and avoids free-riding. 

A similar model exists for most markets including MISO, ISO-NE, SPP, ERCOT, NYISO, although with e.g. ERCOT, broader upgrades beyond the interconnection can be shared with the transmission operator funded through transmission rates.

However: In PJM, MISO, ISO-NE and SPP, transmission owners also have the unilateral ability to fund upgrades and charge the interconnection owner for the cost plus a return. There are concerns by FERC that this increases the cost for end consumers because the transmission owners is earning a return for the upgrade vs. this being paid for by the generator - although still to be reconciled that funding of capex should in general earn a return to attract capital, regardless of the source of that capital. The transmission owners should therefore have the right to compete to fund upgrades. But should this be at the transmission owner or the producer’s discretion?

Another concern is around cost allocation - how much of the burden is funded by the producer, and balancing that against burdening the rate base to be shouldered by consumers who may not ultimately benefit from the upgrade.

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Anatomy of an Auction: A Simplified Example of PJM Capacity Auction Clearing

PJM Service Area (inc. DC)

Anatomy of an Auction: A Simplified Example of PJM Capacity Auction Clearing

The PJM annual capacity auction utilizes a "descending clock" mechanism to determine which power generators will be paid to be on standby and ensure a reliable electricity supply for the 65 million people in its territory. While the actual auction is highly complex, this simplified example illustrates the core principle of how the auction "clears" and sets a uniform price for all successful participants.

The Setup: Demand and Supply

First, PJM determines the total amount of capacity it needs to secure for a future year. This is based on forecasted peak demand plus a reserve margin for unexpected events.

Let's assume for our example:

• PJM's Required Capacity: 10,000 Megawatts (MW)

Next, power plant owners offer their available capacity into the auction at the minimum price they are willing to accept to be available for that year. These offers come from a variety of sources with different costs.

Here are our hypothetical power plants and their offers, ranked from lowest to highest price:

Power Plant	Resource Type	Capacity Offered (MW)	Offer Price ($/MW-day)	Cumulative Capacity (MW)
Plant A	Nuclear	2,000	$10	2,000
Plant B	Hydroelectric	1,000	$25	3,000
Plant C	Coal	3,000	$50	6,000
Plant D	Natural Gas (Combined Cycle)	2,500	$90	8,500
Plant E	Natural Gas (Peaker)	2,000	$150	10,500
Plant F	Older Coal	1,500	$175	12,000
Plant G	Demand Response	500	$200	12,500

The Descending Clock in Action

The auctioneer starts the "clock" at a high price, well above what anyone has offered. At this high price, all the power plants are considered "in" the auction because the price is favorable to all of them.

The auctioneer then systematically lowers the price in rounds. As the price on the clock drops, it will eventually fall below the offer price of some of the more expensive power plants. When this happens, those plants will drop out of the auction as the price is no longer acceptable to them.

Let's simulate the process:

• Clock Price: $250/MW-day: All plants (A through G) are "in." The total available capacity is 12,500 MW, which is more than the 10,000 MW needed.

• Clock Price: $180/MW-day: The price is still above Plant F's offer, so it remains in. All plants from A to F are still in.

• Clock Price: $160/MW-day: The clock has now dropped below Plant F's offer of $175/MW-day. Plant F drops out. The total available capacity is now the sum of Plants A, B, C, D, and E, which is 10,500 MW. This is still above the 10,000 MW requirement.

• Clock Price: $150/MW-day: At this price, Plant E, with its offer of $150/MW-day, is still "in." The total available capacity from Plants A through E is 10,500 MW.

The Clearing Price: Where Supply Meets Demand

The auction "clears" at the price where the amount of offered capacity is just enough to meet PJM's required capacity.

In our example, when the price dropped and Plant F exited, there was still 10,500 MW of capacity available from the remaining plants (A, B, C, D, and E). Since this is the first point at which the available capacity meets or just exceeds the 10,000 MW requirement, the auction is over.

The clearing price is set by the offer of the last generator needed to meet the demand. In this case, that is Plant E, the natural gas peaker plant. Therefore, the clearing price for all successful participants is $150/MW-day.

The Results: Who Gets Paid and How Much

Here's the final outcome of our simplified auction:

• Cleared Generators: Plants A, B, C, D, and E.

• Uncleared Generators: Plants F and G did not clear because their offer prices were too high. They will not receive a capacity payment.

• The Payment: All the cleared generators (A through E) will receive the same clearing price of $150/MW-day for their committed capacity for the specified delivery year. This is a key feature of the auction – even though Plant A offered its capacity at a much lower price, it still receives the higher, market-clearing price.

This example demonstrates how the PJM capacity auction is designed to secure the necessary amount of power at the most competitive price, with the final clearing price being set by the last resource needed to ensure grid reliability.

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