Wind energy advocates have cheered as each of seven states in the US adopted "Renewables Portfolio Standard" (RPS) laws over the past three years. A closer look reveals, however, that six of these state RPSs are missing one or more of the elements necessary to create competitive renewables markets that will support new projects. Without the shining example of Texas, it would be easy to write off the RPS as an ineffective policy. That Texas is now, by far, wind's hottest market in the United States is evidence that the RPS -- done right -- can live up to its potential to advance wind and other renewable resources at least cost.
Though most of these state laws are formally or informally referred to as "Renewables Portfolio Standards," they differ in important respects from the policy that was originally put forth by the American Wind Energy Association (AWEA) in 1995 (box). Likewise, in Europe, the RPS and other terms, such as "tradable green certificate obligation," are being bantered about without any commonly accepted definition. But the details are critical, as the uncertain -- and in some cases useless -- results in six of the seven US states make clear.
Of all of them, Maine's is the most poorly constructed law, lacking six of ten crucial elements (table). As such it holds no hope of supporting new renewables development of any kind and will do little to support projects already on-line. Connecticut regulators had the opportunity to do it right, but botched the job and are now being taken to court. In Massachusetts, the law does not require trading of renewable energy credits or automatic penalties and contains other potentially crippling ambiguities that must be resolved by regulators. In Nevada, New Jersey, and especially Wisconsin, less-than-ideal laws still leave hope that regulators will rescue the law from potential ineffectiveness or inefficiency. Hanging in the balance are several thousand megawatts of new renewables capacity that could be required in the six states if regulators correct legislative shortcomings.
These hastily drafted RPS provisions were the consequence of political battles over electric industry restructuring in which relatively small RPS requirements were tossed to politically weak environmental and renewables lobbies to dress up much larger financial benefits bestowed on utilities and large energy consumers. In some cases, opposing political interests succeeded in watering down the RPS. In others, renewables advocates realised too late that key provisions were missing. Regulators then put the RPS last on their list of implementation priorities as they struggle to overhaul the entire electric industry.
Supporters of the RPS concept are fortunate that evidence is already coming in from Texas -- where the law requires 2000 MW of new renewables capacity by 2008 -- that decently constructed RPS legislation and thoughtful implementation will lead to real markets for wind energy. A month after regulations became final, TXU Electric -- not one of the RPS's great supporters -- took a step towards compliance by issuing a request for proposals for 500 million kilowatt-hours' worth of tradable renewable energy credits annually (Windpower Monthly, February 2000).
A market standard -- an obligation for a fixed volume of renewables power supply -- will result in new capacity (and capital improvements to existing capacity) only if it is structured in a way that gives investors confidence that prudent investments will be profitable. The RPS was carefully designed with this primary goal -- a dependable and predictable market -- in mind.
Such a market needs a long-term, growing renewables obligation on all entities competing to supply the retail market -- effectively the market which all electricity passes through. If it is not long term, renewables prices will be higher and more volatile because developers cannot recover their costs over a reasonable period of time. What's more, "boom and bust" cycles will be the norm if the percentage requirement is not increased gradually rather than in large, sudden jumps. As long as it is long term, renewables will become competitive over time and the RPS will gently sunset of its own volition. But if it is not equally applied, particularly to the utilities in all of their new forms, as well as to competing newcomers, it will discourage overall competition -- if it works at all.
To ensure the obligation is taken seriously, stiff per-kWh non-compliance penalties must be imposed on any competing electricity retailers -- the new-style "suppliers" of liberalising European markets -- who fail to comply. Without penalties there is no secure market for investment in new renewables development, so investors will demand a higher return to compensate for the uncertainty. This will push up the price of renewable power for retailers, thereby adding to the overall cost of the RPS. Automatic penalties imposed for each required tradable credit not produced by a retailer will give investors confidence that there will be potential buyers for their product. A penalty is a strong incentive for a retailer to work collaboratively with renewables suppliers to build new capacity. And if penalty revenues are used immediately to buy credits, investors can safely invest in promising projects even if they have no contracted buyer.
The obligation must be for a sufficient volume of renewables. If the demand the RPS creates is less than the available supply, no new renewables capacity will result. This seemingly obvious goal, however, has not always been achieved because it requires careful handling of existing renewables supplies. Large hydropower and non-renewables must be excluded entirely from the list of resources qualified to meet the obligation -- a principle that has nevertheless been violated in more than one RPS.
To maximise the efficiency with which the renewables goal is met, and thus to minimise costs, the original RPS was also designed to be a flexible requirement -- a tradable obligation. This is not just an optional embellishment, but an integral part of the policy. Basing the RPS on a system of tradable renewable energy credits provides both retailers (the entities selling power to the retail market) and suppliers (of renewable energy) with considerable advantages.
With tradable credits, retailers need not own or buy renewable energy if they have no particular interest or expertise; they can simply buy credits on a short or long term basis -- and bank them for future use. Retailers who do get involved in renewable energy acquisitions can use credits to reduce risks. Credits can be bought to make up any production shortfalls or sold to take care of any excess. And the compliance period can be elastic by allowing a period, say three months, for making up any shortfalls, thereby reducing the risk of non compliance. Another advantage of tradable credits, and of particular benefit to wind energy producers, is that they can be sold at any time, regardless of when the power is generated.
The tradable credits system also has a spin-off benefit: it functions as a simple accounting system to prevent cheating, which could otherwise introduce enough market uncertainty to frighten off investors. Without tradable credits, keeping track of whether a retailer has or has not fulfilled its obligation requires tracking all renewable energy transactions within an entire electricity trading region, a hugely complex task. A credit-based verification system is easier because the state just issues credits for verified production from a renewable energy plant and collects credits from the retailer at the end of the compliance period.
Failures IN THE MAKING
A long term, growing and tradable obligation of sufficient size, its equal application to all retailers and stiff penalties for non compliance are the basic principles of the RPS. Though the integrity of the policy can be retained with some variation, the principles must be preserved. Get one wrong, and the RPS will not live up to its full potential. Make a few fundamental mistakes and the law may be completely ineffective in promoting renewables. Many of the basic principles have been violated in the states attempting to establish RPS policies.
Of all seven states with so-called RPS laws, only Texas has got it right. The other six so far fail to include one or more of the basic RPS principles. Indeed, in only three states, Connecticut, Maine and Texas, can the RPS be termed long term. Even if it had been long term, the Maine RPS is a total disaster (despite a seemingly high 30% obligation), violating more principles than any other state. It will result in no new renewables capacity. In Connecticut, only a favourable court ruling will rescue the law from disaster and regulative improvements are needed as well. In Nevada and Wisconsin, favourable regulatory interpretation is needed to salvage flawed RPS laws -- and those same flaws may lead to court challenges. The same is true in Massachusetts, where more legislative action is needed for an effective RPS. New Jersey's implementation regulations have been drafted, but the final version needs improving if the RPS is to have the desired effect.
None of the six have implemented a system of tradable credits. In Maine and Massachusetts, no trading will be allowed unless and until regulators recommend it to the legislature and legislation is adopted. Massachusetts is now grappling with the difficulty of verifying compliance without a credit system. Maine's electric retailers have an obligation to demonstrate compliance, but just how compliance will be proven is unclear -- and with no tradable credits to serve as proof, a bureaucratic nightmare threatens. As for the other states, RPS statutes allow for credit trading, but New Jersey's draft regulations and Connecticut's final ones fail to even address the topic, while Nevada will decide later this year.
The RPSs of Connecticut, Massachusetts and Nevada also have serious shortcomings because they do not apply equally to all providers of electricity. In Connecticut, consumers who do not switch to a competitive provider automatically receive their electricity from the "default providers," the two former monopoly utilities. These will serve nearly all the market for the next several years. Yet the RPS does not specifically apply to them, with the result that the default providers have wriggled off the RPS hook. A court decision awaits.
Renewables advocates in Massachusetts are grappling with a similar problem of unequal application, again caused by lack of legal clarity, and things are even more foggy in Nevada. Here the exemption of the Sierra Pacific Power utility (presumably due to the geothermal resources already in its portfolio) is complicated by the nature of the RPS, which fixes the total percentage of the state's electricity that must come from renewables, rather than imposing a fixed percentage obligation on each provider of electricity. Exempt one provider under this system and the obligation on others will increase markedly, if the state's goal is to be achieved. The state Public Utilities Commission (PUC) is grappling with the issue.
Five of the seven RPS laws have also failed to stipulate effective penalties for non compliance. This makes them potentially impotent because of the considerable degree of market uncertainty this introduces. In Maine the so-called penalty is equal to the cost of compliance and retailers can anyway choose to buy-out of the obligation by paying into a renewable energy R&D fund. Adding further to the uncertainty, the Maine RPS also allows too lenient a period for compliance -- fully 12 months for those who have met two-thirds of the obligation -- compared with a tight three months elsewhere.
Nevada's law has no penalty provision, though the PUC has recognised that its only available weapon, license suspension and revocation, "is an extreme measure." It is considering the introduction of automatic penalties. Massachusetts regulators do not even have the freedom to introduce penalties since they must obtain the legislature's approval on a "mechanism for assessing fines and penalties for violations" in relation to a potential system of tradable credits. Connecticut and draft New Jersey regulations both rely on a vague set of potential penalties that may be imposed after administrative reviews. In Connecticut this would only happen after considerable investigation, among other things, of the past general misdeeds of the defaulting company and whether it had made a "good faith effort" to comply with the law. The RPS can even be suspended for two years if suppliers successfully claim they cannot meet the requirement.
It would seem obvious that the demand for renewables created by an RPS should exceed the existing supply so that the total amount of renewable energy grows. But, because of overly broad or vague definitions of qualifying renewable resources, with the exception of Texas and Wisconsin, state RPSs won't necessarily create new demand.
Maine is a particular culprit on this front. Its eligible resources include fossil fuel cogeneration and hydro up to 100 MW, existing or new, thus supply greatly exceeds the demand created by the 30% purchase obligation. As a consequence, the market is providing a low renewable energy premium of just $0.001/kWh or so, not enough for wind. Even a pending amendment to exclude cogeneration would not make enough of a difference.
In Nevada, geothermal is the problem. The RPS is only for a low 0.5% of any-source renewables, but the law fails to exclude larger existing quantities of geothermal power. As such, a potential 100 million kWh annual market for wind power is blocked unless remedied by regulators. Connecticut and Massachusetts deal with the issue of existing renewables with two-tiered standards. Their "new renewables" tiers might be closed to existing hydropower, including vast Canadian resources, but in Connecticut the "base tier" is open to large hydro and this might also be the case in Massachusetts, pending the outcome of talks.
By not excluding large hydro, several of the RPS states in this east coast region are limiting the market for wind. Even though the "base tiers" are not the primary wind markets, opportunities could emerge if demand came close to exhausting the other renewables supplies. Excluding hydropower altogether is far preferable, however, since its variability can create volatility in RPS markets.
An additional problem with some RPS laws could make wind investors nervous: some states include increasingly cost-effective natural-gas fuel cells on the list of eligible, or potentially eligible, "renewables." Only Nevada and Texas exclude fossil fuels altogether, even if used in fuel cells. In the other states, potential investors in wind projects will have to size up whether natural gas-fired fuel cells will prove to be more competitive than wind.
Successes of implementation
To date, Texas is the only state that has implemented an RPS policy that contains all the essential elements. Over several months, problems were identified and solutions or compromises reached (such as how to incorporate existing renewables into the obligation); outside organisations enlisted for specific jobs (an independent body will administer credit trading); and the details of implementation were carefully thought out (credits will be issued six months before the requirement takes effect in January 2002 and extra compliance flexibility will be provided in the early years). Of most note, it is the only state which has implemented a system of credit trading.
The advantage of a tradable credit based RPS was obvious in Texas: the vast territory of the state -- 679,000 square kilometres -- is served by four "electric reliability regions" with constrained transmission connections between them that cannot accommodate the physical transport of large quantities of renewable power. Unlike fossil fuels, renewable energy cannot be shipped via pipeline or tanker. Using tradable credits to separate the environmental value of the power from the power itself will allow all of Texas to benefit from the least-cost renewable resources in the state -- a large portion of which are wind resources in far west Texas.
Care was taken with the details of implementation. There is a three-month period after each compliance year to allow electricity providers to make good any obligation shortfall. This increases the credit market's liquidity. Texas will provide further flexibility in the early years by allowing "5% deficit banking" which permits a 5% shortfall during the year as long as it is made up in the following year. Further exceptions will be granted for events or circumstances (carefully defined) that are outside of a party's reasonable control. Credits will have a three-year life, in part to accommodate natural variations that may occur with intermittent renewables.
Texas is not alone in including other basic RPS principles. Maine, New Jersey and Wisconsin for the most part succeeded in placing an equal percentage obligation on all retail sellers doing business in the state. Indeed, the Maine and New Jersey statutes explicitly apply the RPS to any entity selling electricity at the retail level, including default service providers. Wisconsin, like Texas, allowed for specific exemptions but these were not the result of an oversight or lack of clarity. They were compromises carefully crafted to avoid undermining the renewables goal.
Texas directed the PUC to enforce the RPS law. In turn, the PUC adopted an automatic penalty at the lesser of $50/MWh or twice the average market value of credits. It falls short of the three-times-compliance-cost penalty advocated in the AWEA model, but it clearly exceeds expected compliance costs and retailers therefore have good reason to meet the obligation instead of seeking ways around it. The public purse will avoid costly administration to enforce compliance in other ways. Ideally, any penalty revenues should have been directed to be used for buying credits; instead they are allowed to disappear into the general state coffers. But because the penalty is strong and likely to result in compliance, the potential damage to the RPS is largely academic.
By employing stiff penalties, Texas avoids the potential "Catch-22" of RPS legislation where retailers fail to make a sincere effort to obtain renewables from potential suppliers, and then, when no renewables are built, claim that no renewables are available. Only if a state stands firm in concluding that no real effort was made to comply with the obligation can a retailer be prevented from booby-trapping the RPS. Texas regulations allow the penalty to be waived only in extreme cases. The Catch-22 problem is avoided by this statement: "A party is responsible for conducting sufficient advance planning to acquire its allotment of [credits]. Failure of the spot or short-term market to supply a party with the allocated number of [credits] shall not constitute an event outside the competitive retailer's reasonable control."
The compromise reached in Texas over which energy sources are eligible for meeting the RPS obligation is a useful model for other states with existing renewables, particularly hydro. A new renewables requirement is in place within a cumulative renewables requirement that includes 880 MW of existing, mostly hydro, resources and some wind. The PUC accepted a compromise that only the new renewables requirement will have to be met by retailers, but existing renewable energy will offset the new renewables requirement for retailers who have contracts with existing facilities. Existing renewables will not, however, qualify for tradable credits. To allow for the wet year, dry year nature of hydro's volatility, offsets will be based on ten years of average generation.
The amount of new renewables that is offset will be allocated across the smaller, remaining base of retail sellers. The obligation of those sellers will thus be higher than it would have been if the retailers with existing renewables were obligated to support an equal share of new renewables, but far lower than it would have been if a cumulative (existing and new) requirement were applied to all retailers.
To ensure that the cumulative legislated renewables requirement is met, if any existing renewables capacity is retired, the new renewables requirement will be adjusted upward to replace the retired capacity two years after the retirement occurs. And the PUC will deny eligibility to any renewable facility whose above-market costs are already being accounted for in customers' electricity bills, for example as part of the "stranded cost charges" a utility was allowed to levy as part of its deregulation. New hydropower facilities still qualify under the new renewables requirement in Texas, but they are not considered to be a strong contender against new wind.
Much of the Texas success story can be credited to a solid law and a hardworking implementation group, headed by dedicated PUC staff, in which environmentalists and members of the wind industry participated. Its RPS serves as an excellent example for states still in the implementation stage. If adequate pro-renewables advocacy resources are invested in those states, things could still turn out well.
A federal RPS is still a long way from the statute books. But in Congress, where five RPS proposals await uncertain action on larger electric industry restructuring legislation, an opportunity exists to effectively apply the RPS nationwide -- and correct the problems with any faulty state RPSs. Some federal proposals are very strong while others, notably that of the Clinton Administration, have potentially fatal flaws that must be corrected through persuasive advocacy. Thankfully, in less than two years' time, advocates will be able to point to an RPS elegantly in action in Texas as evidence that the policy, done right, can deliver renewable energy at an affordable cost.