New England's Wholesale Market Treatment of Wind Evolves as Penetration Increases
During 2013, ISO New England (ISO-NE), the region's independent system operator, continued to address a range of issues that impact wind power's access to and participation in the regional power market. These issues cover the integration of variable resources; the forward capacity market; bidding rules in ISO's energy market; and transmission congestion, planning, and cost allocation. Many of the topics are under active consideration, and depending on the outcome, they have the potential to encourage or discourage wind development in New England.
Strategic Transmission Analysis Reveals that Local Issues Are Most Important for Wind Integration
ISO-NE's Strategic Planning Initiative is a collaboration among ISO-NE, the six New England states, and various regional stakeholders. The initiative is focused on finding solutions for five major challenges in the region:
- Resource performance and flexibility
- Increased reliance on natural-gas-fired capacity
- Retirement of generators
- Integration of a greater level of variable resources
- Alignment of markets and planning needs improvement.
These challenges became the drivers for the ISO-NE Strategic Transmission Analysis (STA) that began in 2011. At the outset, the STA study had several objectives, including addressing the implications of large generator retirements on transmission system requirements, the transmission reliability implications of those retirements, and integrating energy production from the growing role of wind and other renewable resources.
The basis for the STA was a 2009 study performed for the New England Governors that created a blueprint for integrating 2,000 megawatts (MW) of wind capacity. The STA examined the transmission needs for integrating 4,000, 8,000, and 12,000 MW of wind energy capacity and presented initial results in the spring of 2012. ISO-NE did not finalize the study in 2012 as planned because it concluded that the initial analytical approach would not yield meaningful results.
In early 2013, ISO-NE refined and narrowed the scope of the analysis which, among other things, called for giving equal importance to local transmission issues as well as regional transmission system issues when integrating wind resources. The change in analytical approach highlights important differences between ISO planning and operations, the implications of which recently become apparent. ISO-driven curtailments for some wind generators in the past 1 to 2 years may be much more significant than plants had expected based on their interconnection studies (due to the differences between minimum standards applied for allowing projects to interconnect to the system and reliability criteria applied by system operators to avoid disruptions in the event of contingencies). ISO has acknowledged that:
- In many constrained areas identified in the study, first-in wind generators have quickly exhausted limited existing system margins, resulting in the need for more significant system upgrades for subsequent generators
- Most recent wind curtailments are due to local constraints.
These issues are not universal; rather they primarily impact wind plants interconnected far from load in some of the "weaker" edges of the transmission system where wind variability is material in comparison to local loads. Going forward, ISO-NE will identify conceptual alternatives for wind development in different areas of the region rather than a uniform, system-wide approach.
Forward Capacity Market Changes Affect Wind Resources
In December 2012, ISO-NE filed its forward capacity market (FCM) re-design proposal with the Federal Energy Regulatory Commission (FERC). The New England Power Pool, the governing body consisting of the region's market participants, previously rejected ISO's market re-design package but failed to develop its own consensus around an alternative proposal. The ISO filing included a proposal for a minimum-offer price rule beginning with Forward Capacity Auction (FCA) 8, which takes place in February 2014 for the 2017-2018 commitment period.
Minimum-Offer Price Rule Could Take Renewables out of Market
FERC had ordered ISO-NE to implement a "buyer side mitigation strategy" similar to the ones in place in the New York ISO and PJM Interconnection markets. In the minimum-offer price rule construct, a benchmark capacity price for all types of new resources is developed and used to set an offer floor below which that type of resource could not offer in the capacity auctions. If the auction price drops below the floor for a given type of resource, those resources would automatically be removed from the auction. For FCA 8, the offer review trigger price for onshore wind is currently set at $14 per kilowatt (kW) per month, which is likely much higher than the expected auction clearing price. In August 2013, minimum-offer review trigger prices for wind were put forth for FCA 9 (corresponding to the 2018-2019 commitment period) at a level of $9.87 per kW per month.
Under a minimum-price rule, policy-driven renewables, including wind generators, would be seen as "out-of-market" and prohibited from offering in the auctions below a price deemed "competitive" by ISO, a price expected to be above market clearing prices. Proposals to provide renewables with an exemption from this rule, allowing new renewable capacity to continue to have the option to offer in the auctions as price takers, have so far failed to garner sufficient support for adoption. Without such an exemption, it is unlikely that any new renewable resources (including those that cleared for the first time in FCA 6 or FCA 7) will clear in the forward capacity auctions and reap any capacity market revenues.
A participant may submit an offer below the trigger price, provided it includes justifying documentation. In advance of the auction, individual resources can request a project-specific floor price from ISO based on actual project costs or a project-specific exemption through a Section 206 filing with FERC. However, this approach does not provide any guarantee to developers of new resources that their projects would receive exemptions or clear the auctions. In its review of requests to offer below an established trigger price, ISO-NE will only accept "in-market revenues" as part of justifying documentation, which means revenues from renewable energy certificates and federal tax incentives for wind cannot be included. In examining the assumptions used to derive the FCA 9 proposed wind trigger price, it appears many proposed wind projects may be able to successfully seek a lower price floor due to higher expected capacity factors and/or lower installed costs. If approved, lower minimum prices may allow some wind projects to participate in the capacity auctions.
When the FCM market re-design filing was submitted to FERC, numerous parties filed comments in favor of various exemption provisions for renewables from the minimum-offer price rule, but FERC ultimately accepted ISO-NE's filing and rejected exemption requests. FERC did encourage ISO-NE to conduct a stakeholder process with the aim of developing such an exemption. Even if an exemption is developed and accepted, it is unlikely to be implemented by FCA 8, or even for FCA 9. In the interim, many if not most wind projects will be precluded from assuming they can secure revenues through the ISO capacity market.
FCM Performance Incentives Bring Increased Risk to Renewable Generators
ISO-NE is also considering a system of performance incentives/penalties imposed on FCM participants for delivered generation during reserve and scarcity events. The proposal is detailed in an October 2012 white paper released by ISO-NE as part of its Strategic Planning Initiative. ISO-NE has proposed a "performance payment rate" of $5,000/megawatt-hour (MWh). Payments to resources with an FCM obligation (those that have cleared in prior FCM auctions and are receiving FCM revenues) that underperform during any hours of scarcity will be reduced by the performance payment rate times the amount of under-performance (number of MWs below its capacity supply obligation). Similarly, over-performance will raise the performance payment rate by the amount of over-performance during those same scarcity hours. This approach is intended to incentivize FCM participants to take actions—which presumably would incur costs that will be reflected in future FCM bids—to reduce the risk of non-performance.
The addition of performance incentives to the FCM greatly increases the financial risks of participating in this part of the wholesale market. Intermittent resources such as wind are at even greater increased financial risk, because of the limited actions they can take to be responsive to the penalty structure. The New England Power Pool is reviewing the range of potential impacts of the ISO's proposal as it moves to finalize the incentive proposal.
Bidding into the Energy Market: Revisions to Timing and Pricing
Another recently adopted change to ISO-NE energy market pricing rules will (pending FERC final approval) affect wind power projects. Today, intermittent generators like wind projects participating in ISO's energy markets can simply bid zero ($0 per MWh) and be assured of being selected and getting paid the real-time market clearing price, a practice referred to as being a "price taker." There are times, however, when the output of all projects acting as price takers would exceed the load. In such instances, ISO-NE operators do not have a clear protocol to follow and often have made dispatch decisions that are not economically optimal. Today there is a $0 price floor on the market-clearing price for energy. ISO-NE energy markets currently do not allow generators to make negative price offers. The proposal under consideration would allow the energy price to go negative, as low as -$150/MWh. This change would benefit wind generators by allowing them to enter negatively priced bids to ensure they are dispatched.
When there is excess generation on the system and the energy price has been set to $0, the ISO does not have a mechanism to make economic decisions as to which generators should be curtailed. Wind generators that receive renewable energy certificates and the federal Production Tax Credit may prefer to pay a small price to continue generating energy to receive these other revenues. With the ability to make negative energy price offers, wind plants should be curtailed less often than they are under current rules.
ISO-NE is also considering the elimination of "self-scheduling." Self-scheduling is a practice in which a generator submits a must-run MW quantity without an associated price to participate in the market as a price-taker. The proposal includes an exemption for wind, which is incapable of economic dispatch on demand. If the changes to self-scheduling rules are passed, wind resources may need to monitor energy market prices more closely, particularly during off-peak hours, so that they can voluntarily reduce output if the energy price falls as low as the proposed price floor.
ISO-NE is also revising its Net Commitment Period Compensation system, which is used to make up any revenue shortfall when a resource is committed and dispatched but not fully compensated. Wind is currently ineligible for Net Commitment Period Compensation payments because it is a self-scheduling resource, but revisions could reverse this and also address two harms done to wind generators from following dispatch instructions:
- If a wind resource receives Production Tax Credit or renewable energy certificate revenue for production, complying with ISO-NE instructions to reduce output below maximum output will cost the generator money.
- If a wind resource must buy back energy that cleared in the day-ahead market because of curtailment, the generator could lose money if the real-time price is higher than the day-ahead price.
In addition, the timing of bids in the day-ahead energy market changed. The new schedule for day-ahead market timing went into effect in May 2013. Under the new timing, the day-ahead market bid period closes at 10 a.m. the day before the operating day instead of 2 hours earlier under the former rules; locational marginal prices, schedules, and constraints are published by 12:30 p.m. instead of 4 p.m.; and the real-time market re-offer period closes at 1 p.m. instead of 6 p.m. Moving the market earlier poses greater risks for wind generators as it decreases forecasting accuracy.
FERC Order 1000 Process
Finally, planning transmission construction and resolving congestion and cost allocation issues continues to be a major challenge for ISO-NE and the integration of variable renewable energy resources. The ISO and the region's transmission owners responded to FERC Order No. 1000, which brings far-reaching changes to the process governing transmission planning and cost allocation. As part of the reforms to electric transmission planning and allocation under Order 1000, each "public utility transmission provider" must "work within its transmission planning region to create a regional transmission plan that identifies transmission facilities needed to meet reliability, economic, and public-policy requirements...."
The public policy requirements would include state programs such as renewable portfolio standards that call for increasing energy from renewable technologies. Transmission facilities that are designated as serving public policy requirements through the transmission planning process could be funded through regional cost allocation. Such a cost allocation would reduce the transmission costs borne by wind developers by spreading the costs across a broad base of customers benefiting from the public policies, thereby reducing the barriers to wind power development.
In May 2013, FERC partially accepted the ISO's/Participating Transmission Owner's (PTO's) filing but required some revisions, including:
- Transmission owners may not retain the right of first refusal for projects selected for regional cost allocation as proposed.
- The process for evaluating public policy transmission proposals must make the ISO, rather than the New England states (as initially proposed), the entity that evaluates and selects the projects that will be built to meet transmission needs driven by public policy.
- The final compliance filing must include a default cost allocation method developed in advance of a transmission project being proposed, instead of allowing states to decide cost allocation on a project-specific basis.
- ISO-NE must address FERC's concerns with transparency and comparability in the ISO-NE planning process.
ISO-NE and the PTOs must submit a subsequent compliance filing with changes to further comply with Order No. 1000.
This information was last updated on 11/11/2013