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With a rich wind resource, massive renewable energy demand and access to the Midwest Independent Transmission System Operator and PJM Interconnection markets, Illinois has emerged as one of the nation’s most important states for wind power. This year marks just a decade since Illinois’ first wind project was built. Now, more than 3.5 GW of wind turbines spin over the state’s vast corn and soy fields. The state is also home to major wind energy firms, such as Invenergy, Acciona, Mainstream, Goldwind, Nordex, Suzlon and Broadwind Energy.

Illinois now ranks fourth in the U.S. in installed wind energy capacity, thanks to a confluence of natural, historical and political factors. Illinois has moderate wind resources, which are located close to load centers in Chicago and, because it has the strongest winds of any PJM state, other states often seek to purchase wind energy from projects in Illinois.

Strong public policy should be another advantage for Illinois: The state’s 25% by 2025 RPS is among the most ambitious renewable energy mandates in the country. However, the complexities of Illinois’ competitive wholesale and retail electric markets have made the law all but impossible to implement, and nearly all the operating wind energy capacity in the state was developed to serve other markets.

Renewable energy advocates are hoping to change that. A major effort is under way to implement revisions that will ultimately determine if Illinois’ RPS law is a landmark success or utter failure.

 

Unintended consequences

To understand the flaws in Illinois’ RPS, it is important to consider the law in the broader context of the state’s power markets. Illinois is a fully deregulated state, meaning individuals and businesses can buy power from the incumbent utility or purchase it from one of nearly 80 alternative retail electric suppliers (ARES) licensed to operate in the state.

Both utilities and ARES are subject to the state’s 10% by 2015 and 25% by 2025 RPS mandates. (Municipal and cooperative utilities are exempt.) By 2008, the competitive suppliers had captured nearly all the commercial and industrial load from utilities, but utilities still maintained most of the load from residential customers. That all changed with the “municipal aggregation” legislation that passed in 2010.

Under a municipal aggregation system, entire cities, towns and counties can vote to leave the incumbent utility and seek another supplier en masse. Cities can even require ARES to bid on the contract to provide renewable power (although this usually means purchasing cheap renewable energy credits (RECs) via one-year contracts).

Since the legislation’s passage, municipal aggregation has surged in popularity, with over 450 communities choosing a competitive supplier – including Chicago, which has nearly 3 million residential accounts. In just three years, Illinois utilities have lost 60% to 90% of their load.

By most accounts, municipal aggregation is a positive development for Illinois. ARES can often deliver power at lower costs, and that is good for consumers. However, municipal aggregation can also have unintended negative consequences. For instance, because ARES sign supply deals whose terms range from a few months to a few years, communities buy wholesale power under contracts for the same time frame. The incumbent utilities – whose power contracts are brokered by the Illinois Power Agency (IPA) – are in a similar position. Because those remaining utility customers can switch to an ARES at any time, the IPA also buys power under short-term contracts.

Unfortunately, lenders are not usually interested in financing a renewable energy project if it lacks a long-term power-purchase agreement (PPA) or other offtake arrangement. But with both utilities and ARES operating on a short-term basis, such PPAs are impossible to find in Illinois’ power market today. (No new base-load generation will be able to secure financing in this market. However, other generators are not trying to build new projects in Illinois today.)

 

A major effort is under way to implement revisions in Illinois’ RPS law.

 

Bucket and budget sweeps

Complicating the problem is the convoluted system by which the RPS is administered. Under the current law, there are three ways for utilities and ARES to comply with the RPS:

This fractured system splits the funds into three “buckets,” each of which fluctuates annually as customers move from utilities to ARES. Neither utilities nor ARES are able to sign long-term PPAs. But what about the ACP fund? The ACP fund is expected to swell to hundreds of millions of dollars in the coming years as ARES capture more of the market and make increasingly larger payments.

The IPA manages the ACP fund, and statute compels the agency to spend these funds on long-term REC contracts. However, Illinois is facing a crippling $44 billion budget shortfall. In an effort to address the problem, state lawmakers have begun using budget “sweeps,” or “borrowing” money from one state fund to use it for other purposes. The ACP fund has been a victim of these sweeps in the past.

Because there is always a possibility that sweeps will be made, the IPA cannot solicit bids for long-term REC contracts – and even if the agency were to seek long-term contracts, lenders and developers would certainly balk at inking a deal with a state agency with a history of having its funds swept.

The current system is certainly not favorable for developers. Fortunately, there is a solution.

 

The solution

The best way to solve the aforementioned problem is to scrap the entire system and move to a single compliance mechanism. Currently, the cost of compliance is embedded on the generation side of ratepayers’ electric bills. New legislation aims to solve the problem by switching the compliance charge to the transmission portion of the bill.

S.B.103, an amendment to the Illinois Power Agency Act, was introduced in the Illinois Senate on Jan. 23. The legislation provides that, for periods beginning on and after June 1, 2014, the IPA’s procurement plans shall include procurement of RECs in amounts projected to be sufficient to meet certain RPS requirements.

Under the proposal, utilities and ARES would stop procuring RECs themselves or through compliance payments to the IPA. Instead, all users of the transmission lines (utilities or ARES) would be charged the same amount, and that charge would be collected by the owners of the transmission lines.

The IPA would never take control of the funds, thus preventing sweeps. However, the agency would be able to direct the use of the funds and could use them on a blended portfolio of short- and long-term renewable resources. All cost caps would remain in place, so consumers and businesses would not pay more than allowed under current law. Additionally, retail competition and municipal aggregation would continue unabated.

The Senate Energy Committee approved the bill before its spring recess in late March. Concerns about the complexity of the bill and its possible impact on ratepayers may bring some amendments to the bill before the spring session concludes on May 31.

Most importantly for the wind industry, the proposed change would help developers finance and build new renewable energy projects, thus helping to shift Illinois’ economy from fossil fuels to renewable energy. After all, that was the original goal of the RPS. w

 

Kevin Borgia is public policy manager at Wind on the Wires, a regional partner of the American Wind Energy Association. Previously, he was executive director of the Illinois Wind Energy Association. He can be reached at kborgia@windonthewires.org.

Spotlight: Illinois

A Plan To Fix Illinois’ Renewable Portfolio Standard

By Kevin Borgia

Legislative changes are needed to close the loopholes that now exist in the mandate in order to ensure Illinois’ RPS works as intended.

 

 

 

 

 

 

 

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