America’s electric grid is undergoing rapid metamorphosis as wind and solar become a significant part of the system: Half of all new generation capacity added in 2014 was from renewables. Nearly 7 gigawatts of solar were installed in 2014 to reach just under 20 gigawatts of cumulative capacity, and 4.7 gigawatts of wind were installed in 2014, pushing total onshore capacity over 64 gigawatts.

But this renewables influx is entering a system designed for very different resources. As low-cost wind and solar evolve to provide more and more electricity, grid operations, power markets and financial structures must evolve along with them.

Some organized markets already have begun transitioning, and while these varied changes reflect different market conditions, the results are similar: increases revenue stability and lower risk for developers. Comparing how contracts and markets are evolving in two parts of the country, California and the Midwest, sheds light on changes that will be necessary as renewables begin to form the core of our electricity mix.

Wind power curtailment and PPAs in a restructured market

In competitive markets, the lowest marginal cost resource should be dispatched first (including demand-side resources like demand response or efficiency). The resource mix is also “security-constrained,” meaning system operators must ensure the dispatched resource portfolio works reliably within system constraints. If wind resources with the same marginal cost find themselves behind a transmission bottleneck, for example, security constraints mean some may be turned down or “curtailed,” either voluntarily or mandatorily.

Because most renewable projects are financed and contracted using power-purchase agreements (PPAs) structured around generated electricity, reducing total output can create significant financial risks. While most PPAs rely on careful analysis of wind resources and probabilities about the average number of hours they’ll be available in a given year (increasingly including expected curtailment), anything improving predictability of expected revenue is a plus for all parties -- meaning market operators must find efficient ways to minimize economic losses while maintaining system reliability.

MISO’s approach to increasing predictability: Economic dispatch for renewable power

The Midwest Independent System Operator (MISO) switched to “economic” dispatch for wind farms in 2011 to improve its operating environment, dispatch more efficiently, and provide a more stable context for PPA-driven wind resources to generate revenue. MISO’s dispatchable intermittent resource (DIR) tariff requires wind farms that began operating in April 2005 or later to offer energy into the real-time market and participate in security-constrained economic dispatch.

Before DIR, MISO wind farms were manually curtailed (that is, grid operators picked up the phone, called operators, and asked them to turn down), creating system inefficiencies, relatively high curtailment rates (3.7 percent of total wind generation), and significant under-delivery penalties for wind farms when real-time conditions did not match their day-ahead forecast.

Shifting to economic dispatch means wind farm operators turn down according to market conditions, not in response to phone calls from MISO, significantly reducing manual curtailment. The most recent data shows only 0.2 percent of total generation is being manually curtailed.

It’s important to note “down-dispatched” wind electricity -- this new market-based curtailment -- is still significant, and overall wind curtailments in MISO have only been modestly reduced since DIR was adopted. However, since manual curtailment was going to happen anyway, economic dispatch reduces uncertainty on financial returns from variable generation.

Transitioning renewables to economic dispatch in MISO has helped address flexibility and reliability concerns, given grid operators more granular control, and allowed wind developers to thrive in the large MISO footprint -- wind now makes up about 7 percent of MISO’s generation overall, and more than 20 percent in certain regions.

In the near term, MISO’s DIR improves financial predictability for wind generators, driving down capital costs and improving system reliability. In the long term, though, MISO states must come to terms with renewable curtailment, foregoing nearly free, zero-carbon electricity production from already-built projects.

Luckily, many solutions are available today to help drive down curtailment, including more physical transmission between balancing areas or constrained locations within a balancing area, increased financial trading between balancing areas, or other flexibility resources like price-responsive demand.

Even without transmission constraints, moving generators to economic dispatch raises long-term questions. How should economic dispatch work when the entire market is flooded with zero-marginal-cost resources? How will grid operators determine which plants get dispatched and which get curtailed when the marginal generating unit bids the same price as many other units over long periods of time?

California’s approach to increasing predictability: New kinds of contracts

While including wind and solar farms directly in economic dispatch may work for MISO, things are somewhat different in California. Developers -- particularly solar developers -- have become wary of potential curtailment increases in the future and are structuring new contracts limiting curtailment to a fixed amount (e.g., 5 percent of potential output). With these new contracts in place, grid operators can curtail beyond this amount, but are required to compensate developers as if they had not. As it turns out, a variety of differences between MISO and California underlie these different approaches, and understanding these dynamics provides lessons for grid operators and policymakers across the country.

First, California’s electricity system is very different from MISO’s. The two regions have similar levels of wind energy penetration (7 percent), but California also integrates significant in-state solar (5 percent), biomass (3 percent), and geothermal (6 percent), according to 2014 EIA data, putting the state on track to meet its 2020 goal of 33 percent renewable energy.

Second, within the California Independent System Operator (CAISO) territory, renewable procurement is dominated by the three big investor-owned utilities, meaning PPAs turn over effective control of generation output to this limited number of utility offtakers. Utilities optimize the whole portfolio of resources they own or control, and a scheduling coordinator works with CAISO to curtail variable generation as a function of the utility’s needs. For example, a utility may pre-purchase fuel for delivery on a given day and therefore choose to burn that fuel in a natural gas plant it controls, rather than schedule the full output from a variable generator.

Under these circumstances, the utility incentive to optimize its resource portfolio may not align with renewable project developer incentives to maximize revenue, creating a degree of risk to be addressed in contract structures.

Third, California’s grid is comparatively inflexible during some periods of peak renewable generation. This lack of flexibility comes from local capacity requirements, legacy contracts protecting resources that could otherwise be turned down, the way in which imports are treated in the market, and barriers against balancing resources inside CAISO territory with adjacent territories.

Comparing two recent grid integration studies (one for California’s investor-owned utilities and one for a group of advanced energy companies) illustrates the flexibility challenge. By varying key assumptions on local capacity requirements, resource mix, and interactions with other states, the utilities showed a 50 percent renewables scenario with 4 percent to 9 percent curtailment in 2030, while the advanced energy companies showed a 54 percent renewables scenario with only 1 percent to 1.5 percent curtailment.

This context shows a risk that significant curtailment might be necessary in certain hours by the year 2020 in CAISO. Unlike in MISO, where real-time market prices are effectively reducing output from wind as needed, California is unsure whether operators will similarly curtail, and has therefore proposed dropping the bid floor for economic dispatch in real-time markets to negative $300 per megawatt-hour. By contrast, MISO secures down-dispatch with prices in the negative $11 per megawatt-hour range. California’s floor leads operators to curtail when necessary to avoid significant penalties, but this price territory also poses significant risks to generators.

Lessons for policymakers

Policymakers can learn several lessons from the MISO and CAISO experiences. First, integrating variable resources like wind and solar into economic dispatch is certainly possible, creates an overall benefit to all parties involved, and works best in a large and well-functioning market with multiple offtakers and market actors who are free to optimize for economics without too many contractual or other barriers. In MISO, the DIR transition has improved system operation, providing developers with better revenue predictability and lower risk.

Second, as variable resources deliver a larger share of total generation, addressing flexibility issues and other inefficiencies in the existing grid becomes increasingly important. In California, developers already concerned about future potential curtailment have begun addressing risk by adjusting contract structures to limit risk. Policymakers will need to consider not only how new entrants need to adapt, but also how current practices, policies, and systems built for incumbent stakeholders must change to maximize overall efficiency and value system resources.

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Eric Gimon, Robbie Orvis and Sonia Aggarwal represent America's Power Plan.

Thank you to Jeff Bladen, Mark Ahlstrom, Jim Caldwell, Uday Varadarajan, Arno Harris, Michael Wheeler, and Andres Pacheco for their input on this piece. The authors are responsible for its final content.