New California Rules May Complicate Financing of Renewable Energy Projects

New California Rules May Complicate Financing of Renewable Energy Projects

June 11, 2011

Proposed changes in market rules and in future power purchase agreements could significantly complicate the financing of intermittent renewable projects being developed for the California market.

The new rules provide strong economic incentives for utilities to “curtail” — or cut back — electricity from intermittent resources during periods when market electricity prices are falling. Changes recently approved to the form contracts used by the large California utilities to buy electricity from independent generators make it likely that a portion of the curtailment risk will be passed from the utility to generators.

The proposed market rules would also remove protections that currently shield intermittent renewable resources from much of the risk of incurring liability for uninstructed energy payments that are required when a generator delivers more or less energy than scheduled during an hour.

As such, the proposed market changes will at minimum complicate estimation of project revenues and could at worst erode a project’s profitability.

Revenue Risks for Renewable Contracts

Recent power purchase agreements for wind and solar projects in California have typically been structured as “must-take” agreements with fixed prices per megawatt hour. The offtaker accepts power from the plant owner regardless of the current market price, pays the plant owner the agreed-upon fixed price for the power, delivers the power to the grid operator, and receives payment based on the current market price. As such, the utility or its ratepayers bear the market price risk while the project owner assumes the production risk.

Meteorological conditions and project performance characteristics are the key factors in determining production risk. Reasonable estimates of plant production can be developed using site-specific historical meteorological data and technology-specific performance data. Therefore, production risk does not generally impede project financing as long as the plant is sited in a suitable location and built with high-quality
components.

Potential changes in California’s market rules may provide economic incentives for intermittent generators to allow curtailment of deliveries when market conditions are unfavorable. This is called “economic curtailment.” At the same time, regulators are encouraging utilities to shift some of the market price risk from ratepayers to project owners by not fully compensating suppliers for lost revenue in the event of an economic
curtailment. Similar shifts are occurring in other jurisdictions nationwide.

Economic curtailments can cause a significant loss of revenue even when limited to a certain number of hours per year, since curtailments can occur when a project’s output is high. The risk is generally greatest for wind projects, since wind is often blowing the strongest when demand is low and curtailments are most likely to occur.

The risk to project revenues can be bounded only through an understanding of the rules governing economic curtailment, current and future market conditions that may contribute to curtailments, the utility’s incentives to curtail, the ability of project owners to receive production tax credits and renewable energy credits for curtailed deliveries, and contract provisions for compensation in the event of a curtailment.

Changing Rules for Renewable Curtailments

Curtailment incentives for project owners and utilities can diverge when market prices fall.

Since wind and solar projects generally have low marginal costs of production, it is in the interest of project owners with fixed-price contracts to keep their plants operating regardless of the market price. This incentive is particularly strong for projects that are eligible for tax credits or renewable energy credits that are tied to production.

Utilities have different incentives: when the market price falls below the contract’s fixed price, the utility has a negative contribution to margin for each unit of energy purchased under the fixed-price power contract, meaning that it is generally in the interest of the utility to curtail purchases from the project.

As more renewable resources are being developed with insufficient transmission or load support, oversupply and congestion conditions are arising with increasing frequency, leading to electricity prices in certain locations that are significantly lower than prices in the power contract. In fact, it is not uncommon for market prices to be negative, particularly in areas with significant wind development.

Current market rules in California encourage must-take intermittent renewable power transactions to be self-scheduled outside of the market, meaning the owners of renewable power plants generate and deliver power to the purchasing utility regardless of market prices.

These transactions come with very high penalty prices for curtailment, effectively eliminating the opportunity for the purchasing utility to curtail output from the generator except if needed to preserve system stability or otherwise avoid an emergency situation. This provides a benefit to project owners, since they are guaranteed the price in the power contract plus relevant tax credits and renewable energy credits for nearly all the power that they can produce. It conflicts with the interests of the purchasing utilities, which would prefer to curtail their purchases from projects when market prices fall below the price in the power contract.

The California Independent System Operator or “CAISO” has proposed market rule revisions that would encourage intermittent resources to allow curtailment in the event of very low market prices. The proposed changes will almost certainly increase the frequency of curtailments and the amount of uninstructed energy penalties for intermittent renewable projects.

Currently, prices in the CAISO markets have a floor of
-$30 per mWh. At a market-clearing price of -$30 per mWh, a supplier to the CAISO would have to pay $30 per mWh to deliver power to the CAISO. The proposed market rules would reduce the floor price to -$300 per mWh in an attempt to encourage more projects to bid a price point for economic curtailment. In other words, the bidder would submit a price at which it would be willing to allow the CAISO to curtail deliveries in order to avoid potentially paying as much as $300 per mWh to deliver.

In addition, the CAISO would phase out its “participating intermittent resource program” and eliminate the benefits that the program confers to participants. Currently, participants agree to a number of conditions, including self-scheduling and paying for CAISO meteorological forecasts, in exchange for being shielded from some of the cost of output variability. In particular, other resources are subject to “uninstructed energy payments” if they do not deliver to the CAISO the expected amount of energy in each 10-minute period. However, program participants are liable for these payments only for deviations from expected amounts of energy deliveries over an entire calendar month. Without this program, intermittent projects would lose this benefit, and their uninstructed energy payments would be calculated every 10 minutes without the benefit of netting over-deliveries and under-deliveries over the month.

The CAISO’s proposal is subject to considerable controversy. Market participants have proposed alternatives that may subject intermittent resources to less market risk.

One approach is to follow more closely the framework that the Federal Energy Regulatory Commission approved in February to bring wind resources into the Midwest Independent System Operator’s security-constrained economic dispatch process. Under this framework, many wind projects will be required to participate in the MISO market instead of using self-scheduling. However, projects will be allowed to update their schedules up to 10 minutes prior to the time of delivery, and, as with other resources, they will be assessed uninstructed energy payments only for deviations that remain outside an 8% tolerance band for four or more consecutive five-minute intervals within an hour. In addition, these requirements will apply only to wind projects that began operating after March 2005, that do not meet certain requirements demonstrating that the project has firm transmission rights, and that are not “qualifying facilities” under the Public Utility Regulatory Policies Act. (See related article in this issue starting on page 21.) Notably, MISO had requested to apply these requirements equally to both wind and non-wind intermittent resources, but FERC ruled that non-wind intermittent resources should continue to be allowed to self-schedule.

The CAISO has not responded directly to the proposal to model its curtailment rules after the MISO rules. However, given the contentiousness of its initial proposal, the CAISO has announced that it will issue a revised proposal that will again be open to public comment. This will delay approval of the proposal until the end of June at the earliest. Further delays are possible.

Curtailment Risk Sharing

Economic curtailment can be used to shift some of the market price risk from the purchasing utilities to project owners.

The amount of risk that is shifted and how the risk sharing is structured can vary significantly depending on the terms of the power contract.

In April, the California Public Utilities Commission (CPUC) approved very different risk-sharing structures for the 2011 renewable procurement form contracts to be issued by the state’s two largest utilities.

For Pacific Gas & Electric’s contract, it approved a provision allowing 5% of expected annual generation to be curtailed for economic reasons with generators receiving their full contract price for all curtailed energy. However, generators would receive no reimbursement for lost production tax credits.

For Southern California Edison’s contract, the CPUC approved a provision allowing curtailment without compensation or reimbursement for lost tax credits up to an agreed-upon cap of between 50 and 200 hours per year, with compensation and a discounted buyback option for any excess curtailment.

This decision is likely to be challenged by wind developers and renewable power advocates, particularly since its economic curtailment provisions were substantially revised just days before the decision was approved. Even if implemented as adopted, these form contract provisions are only the starting point for negotiating a power contract and project owners can attempt to negotiate more favorable terms.

As part of the power contract negotiation process, generators should insist on contractual clarity and specificity with regard to the process and rules regarding curtailment. Without such clarity, projects can face significant effect on net income. For example, three wind farms owned by FPL (now called NextEra) were forced to pay $29 million in deficiency payments last year because their contracts with TXU omitted a common contract provision that would have allowed curtailed energy to be counted as if it were generated for the purpose of evaluating compliance with output guarantees.

As curtailments become more frequent, more contract disputes are likely.

Potential disputes are already brewing in California, where Southern California Edison claimed — to the shock of many of its counterparties — that its existing renewable energy contracts allow it an expansive right to curtail without compensation to the generator.

In addition, given that there are often differences between scheduled output and delivered energy from variable renewable resources, disputes regarding the amount of energy that has been curtailed are likely to arise if contracts are not clear on how the amount of curtailed energy should be determined.

Implications for Project Owners

The consequences of economic curtailment for an individual project will depend critically on the market rules and the contract provisions for curtailment procedures and payments.

In general, for projects located in areas with large amounts of wind and insufficient transmission access or local load, project owners and their lenders should anticipate curtailments for new (and possibly for existing) projects.

The amount of curtailment will depend on factors such as the location of the project and the current and planned load, generating capacity, and transmission capacity in the project’s vicinity. Market rules will determine the level of curtailment, whether intermittent generators risk imbalance charges when they deliver more or less power to the grid than expected, and other market risks.

Contract terms are equally important, as they will determine how parties share these risks. As evidenced by the FPL and Southern California Edison disputes, specificity and clarity of curtailment terms in power purchase agreements can avoid large financial surprises.

Unless all curtailment risk is borne by the purchasing utility, curtailment and market risks inject additional uncertainty into the projection of project revenue, which may make it more difficult to finance intermittent power projects.

Project owners and lenders will need to examine carefully the economic curtailment provisions in the PPAs as well as the correlation between generation patterns and market prices: low market prices during periods of high generation could significantly reduce project revenues if the offtaker is not obligated to provide some sort of make-whole payment for curtailed
generation.

Understanding these conditions will allow developers and lenders to incorporate curtailment and market risks into revenue projections and price them into power supply bids.

Properly incorporating market risks into the PPA price increases the probability of meeting financial targets and allows projects to be financed with lower risk premiums.