Ridgewood Energy U Fund LLC Annual Report - Your Investment Guide

Considering an investment in Ridgewood Energy U Fund LLC? This guide offers a clear, concise summary of the Fund's recent performance, financial health, and key risks. We've distilled the essential information from their latest SEC filing to help you make an informed decision about whether this opportunity aligns with your investment goals.

1. Business Overview: Fund Focus & Strategic Shift

Ridgewood Energy U Fund LLC (referred to as "the Fund"), established in 2006, invests in oil and natural gas properties located in the offshore Gulf of Mexico (specifically Texas, Louisiana, and Alabama). The Fund acts as an investor, acquiring "working interests"—meaning it owns a share of the wells—while third-party companies manage the actual drilling and production.

This year marks a significant strategic shift: the Fund has fully utilized its initial investment capital of $60.6 million for projects (from $72.4 million raised in 2006). Consequently, the Fund will no longer invest in new acquisition projects, such as buying new leases. Its future strategy focuses exclusively on managing, developing, and optimizing its existing portfolio of properties.

As of December 31, 2025, an independent reserves report from Netherland, Sewell & Associates, Inc. (NSAI) provides an updated estimate of the Fund's oil and gas reserves and their value.

2. Management Discussion & Analysis (MD&A) Highlights: Operational Performance (2025)

For the year ending December 31, 2025, the Fund held interests in 5 productive wells. However, due to its fractional ownership, this translated to a net interest of only 0.04 wells. All these wells produce both oil and natural gas.

Key Operational Highlights & Challenges:

• Diller Project: One of its two wells (Well #1, started 2015) continues to produce. However, Well #2 (started 2019) permanently ceased production in 2023. The Fund expects to plug and abandon this well by December 2026, incurring an estimated $0.6 million in abandonment costs.
• Marmalard Project: This project includes five wells, with four beginning production in 2015.
  • Well #2 experienced mechanical issues, shut down in early 2024, and despite a failed repair attempt in late 2025, the Fund ultimately plugged and abandoned it.
  • On a positive note, Well #5, which began production in early 2024 but then faced its own mechanical problems, successfully returned to service in late August 2025 after repairs.
  • The Fund anticipates spending an additional $0.9 million for further development and another $0.9 million for future abandonment obligations at Marmalard.

These operational issues underscore the inherent risks and costs involved in maintaining production within the oil and gas industry.

3. Financial Performance & Health (2025)

3.1 Financial Performance Highlights

Management-Related Financials:

• Management Fees: The Fund paid no annual management fees to Ridgewood Energy Corporation (the Manager) in 2025, a decrease from $0.1 million paid in 2024.
• Reimbursements to Manager: The Fund reimbursed the Manager $80,000 in 2025 for accounting and investor relations services, an increase from $60,000 in 2024.
• Distributions to Manager: The Manager receives 15% of the Fund's cash distributions from operations. This amounted to $0.2 million in both 2025 and 2024.

3.2 Asset Valuation & Reserves

The independent reserves report as of December 31, 2025, values the Fund's proved oil and gas assets as follows:

• Proved Oil Reserves: 165.7 thousand barrels (MBBL)
• Proved Natural Gas Liquids (NGL) Reserves: 27.5 thousand barrels (MBBL)
• Proved Natural Gas Reserves: 206.8 million cubic feet (MMCF)

"Proved reserves" represent the quantities of oil and gas that experts can estimate with reasonable certainty to be economically producible from existing wells and planned future developments.

Estimated Value of Proved Reserves (as of Dec 31, 2025):

• Total Future Net Revenue: The Fund expects to receive $4,855.4 million (approximately $4.86 billion) in total revenue from selling its proved reserves, after accounting for operating, capital, and abandonment costs, but before income taxes.
• Present Worth (PV10): This key metric for oil and gas investors represents the estimated value of that future net revenue today, discounted at a 10% annual rate. The Fund's PV10 is $4,342.0 million (approximately $4.34 billion).
  • The majority of this value comes from "Proved Developed Producing" reserves (oil and gas already flowing): $4,122.5 million.
  • A smaller portion comes from "Proved Developed Non-Producing" reserves (existing wells that can be brought online with minor costs): $38.4 million.
  • "Proved Undeveloped" reserves (requiring further investment like new drilling) account for $181.2 million.

Crucial Assumptions for PV10 Calculation:

• Constant Prices: The valuation assumes average prices from January-December 2025 ($64.96/barrel for oil, $12.85/barrel for NGL, $3.205/MCF for natural gas) will remain constant throughout the entire life of the properties.
• Constant Costs: Operating costs, capital costs (including for workovers and the MC300 2ST1 well), and abandonment costs are also assumed not to increase with inflation.
• No Income Tax: The PV10 figure is calculated before any income taxes. Actual cash distributions to investors would be lower after taxes.

These assumptions represent significant simplifications and introduce considerable uncertainty regarding the actual realized value.

4. MD&A Highlights: Key Wins & Challenges (2025)

The Fund experienced both successes and setbacks in 2025:

Wins:

• Successful Production Restoration: The successful repair and return to production of Marmalard Well #5 in late August 2025 demonstrates the Fund's ability to manage operational issues and restore output.
• Quantified Asset Value: The independent reserves report provides a clear, quantified estimate of the long-term value of the Fund's existing assets, with a PV10 of approximately $4.34 billion from its fractional share of proved reserves.

Challenges:

• Permanent Production Losses: The permanent shutdown of Diller Well #2 in 2023 and the abandonment of Marmalard Well #2 in late 2025 represent irretrievable losses of production capacity and incur significant abandonment costs.
• No New Acquisition Growth: The Fund's decision to cease new acquisition projects means future growth will depend entirely on optimizing existing assets, rather than expanding its portfolio through new leases.
• Reliance on Estimates: The substantial asset valuation (PV10) relies on critical assumptions about future prices and costs that may not hold true, introducing uncertainty.

5. Future Outlook & Strategy

The Fund's future strategy centers firmly on its existing assets in the Gulf of Mexico.

• Focus on Existing Assets: The strategy has shifted from growth through new acquisitions to maximizing returns from its current "working interests." This involves ongoing capital expenditures for workovers and the drilling/completion of wells like the MC300 2ST1 to bring more of its existing reserves into production.
• Planned Expenditures: The Fund plans future spending, including $0.6 million for Diller Well #2 abandonment and $1.8 million for Marmalard development and future abandonment obligations. It expects to fund these costs from ongoing operations.
• Long-Term Value Realization: The PV10 of $4.34 billion represents the estimated long-term cash generation potential from its proved reserves, subject to the critical assumptions mentioned earlier.

6. Risk Factors

For retail investors, understanding these risks is crucial:

1. No Public Market & Illiquidity: This is a private investment. There is no public market for the Fund's shares, and significant restrictions exist on transferring or reselling them. This means your investment is highly illiquid, and you may find it very difficult to sell your shares if needed.
2. Oil and Gas Price Volatility: The value of the Fund's assets and its profitability are highly sensitive to fluctuating oil and natural gas prices. Significant price drops could severely impact returns, despite the reserve report's assumption of constant prices.
3. Reserve Estimate Uncertainty: The reported proved reserves and their estimated value (PV10) are only estimates. Actual quantities recovered, revenues, and costs could differ significantly due to market conditions, operational performance, regulatory changes, or geological factors.
4. Assumptions May Not Hold: The PV10 relies on critical assumptions of constant oil and gas prices and costs (without inflation) over the long term. In reality, these factors are highly variable, meaning the actual realized value could be substantially different.
5. No Income Tax Consideration in PV10: The PV10 is a pre-tax figure. Actual cash distributions to investors will be lower after income taxes apply.
6. Reliance on Manager & Operators: The Fund does not operate wells directly. Its performance depends entirely on the expertise and decisions of Ridgewood Energy Corporation (the Manager) and the third-party operators of the wells.
7. Operational Risks: As seen with the Diller and Marmalard wells, mechanical failures, unexpected shutdowns, high repair costs, and the need for costly abandonment are inherent risks in oil and gas production.
8. Geographic Concentration & Natural Disasters: Operating exclusively in the Gulf of Mexico exposes the Fund to significant risks from hurricanes and other natural disasters, which can cause severe damage, disrupt operations, and increase costs.
9. Regulatory & Environmental Changes: Changes in government regulations related to offshore drilling, environmental protection, or taxation could increase operating costs, restrict operations, or impact profitability.
10. Geopolitical Events: Broader global events, such as conflicts or economic downturns, can significantly impact energy markets and demand.

7. Regulatory & Market Environment

• Regulatory Framework: The Outer Continental Shelf Lands Act (OCSLA) governs the Fund's operations. The Fund pays royalties to the U.S. Government (ONRR) ranging from 12.5% to 18.75% of production.
• Deepwater Royalty Relief: While programs like the Deepwater Royalty Relief Act exist to encourage deepwater drilling, the Fund currently does not have any projects that qualify for this relief. This means it does not benefit from reduced royalty payments, particularly when oil and gas prices exceed certain thresholds (e.g., oil above $48.48-$62.95 per barrel or natural gas above $6.06-$10.49 per mmbtu).
• Market Volatility: The Fund remains exposed to the inherent volatility of global oil and natural gas markets, which supply and demand dynamics, economic conditions, and geopolitical events can influence.