But as more and more states reach those first targets, the solar industry is beginning to butt up against what feels more like limits to growth than mandates requiring more.

By Susan Kraemer

How much of a hit will the American CSP industry take and what are some of the options being discussed?

Successes in meeting the earliest Renewable Portfolio Standards (RPS) deadlines of 2010 and 2012 have shown that the industry was able to ramp up faster than policymakers expected, but many of the next deadlines are already oversubscribed.

State level RPS requirements no longer challenge the deployment capabilities of the solar industry, asserts NREL analyst Michael Mendelson at Renewable Energy Project Finance. “Once considered ambitious targets, RPS standards are now relatively easy goals to meet as the wind and, in particular, solar industries are capable of developing generating capacity at scales unheard of even just a few years ago.”

Solar developers have shown that they are able to deploy far greater amounts, and can now develop at a scale unforeseen by policymakers.

In order to meet the first Renewable Portfolio Standards (RPS) deadlines in 2010 and 2012 for targets, the U.S. added renewable energy at an unprecedented annual pace of up to 11 GW annually in each year from 2008.

But going forward, the RPS requirement won’t need that much. Meeting mandates for renewables will require the addition of only up to 6 GW a year until 2020 - typically by developers signing a power purchase agreement (PPA) with a utility to buy renewable power.

“It has become much more difficult to find a PPA with utilities because everybody is close to meeting their RPS,” SolarReserve CEO Kevin Smith tells CSP-Today, speaking as one of the three utility-scale CSP developers operating in the U.S. “So this has put the brakes on a lot of PPA activities.”

“I think the percentages should be raised,” he proposes. “The percentages are low. I think it’s time for the states to start raising their RPS, since most of them have met their requirements.”

Boom and bust

The states most likely to choose CSP to meet some of their RPS are the southwestern states. But most of these have enough contracts to meet the RPS through at least the next few years, and in some cases, like California, through 2020.

Arizona’s Tucson Electric Power and Arizona Public Service exceeded last year’s 3 percent requirement. By 2020, they will need a combined 734 MW. Arizona’s third utility, SRP, will need 470 MW of renewables by 2020.

Nevada’s NV Energy met the state’s 2011 requirement of 15 percent, and will next issue RFPs in 2014 - for 250 MW.

Two of New Mexico’s three utilities are on track to meet (at least the solar portions of) their 2014 targets. PNM expects to be two years late meeting its 2012 target of 10 percent, having missed this year’s target by 3 percent.

In Colorado, Xcel expects to exceed its requirement through at least 2013, and is in compliance through 2021.

Though all three of California’s regulated utilities were two years late in meeting their 20 percent requirement by 2010, they now have three times as many offers as they need in order to meet the 2020 RPS of 33 percent.

Partly, the slowed economy is a factor. Reduced growth in electricity demand has made it easier for utilities to meet their targets. “Load growth figures have been revised downward once they didn’t need as much as they thought,” Smith explains. “The utilities originally identified a need, but then came out with their revised resource plan.

Because the RPS mandates have been framed as a percentage - rather than as absolute megawatts - of new capacity, the moving target got easier to hit as the economy slowed.

Slim pickings
CSP developers like SolarReserve look for U.S. states with an unmet RPS.

“The key is finding utilities that haven’t met their requirements, but we are running out of these,” he reveals. “Nevada is pretty much full up. Arizona is pretty much full up. Colorado is pretty much full up. New Mexico - even California is close to meeting its requirement.”

The recent growth was driven by twin policies: longer term state-level mandates and the one-time jolt of federal incentives. Without the financial incentives at the federal level, many of the projects being built today could not have been built, even with the RPS.

“The state-level RPS’ are the primary catalyst for the strong CSP growth in the US over the past few years,” says BrightSource spokesperson Kristin Hunter.

“Without a RPS, utilities would not likely be making these meaningful procurement decisions - but the federal ITC/cash grant and the Department of Energy Loan Guarantee have been critical to meeting the RPS goals,” she explains, affirming that federal policy and the state mandates have worked synergistically.

Because of the RPS, utilities have a mandate to meet, so they are signing long term power contracts with developers. And because there is a PPA with a utility, investors are willing to risk capital to finance the projects because there is a certainty of return with a 20 year contract with a stable and creditworthy utility.

“With the current unprecedented build-out taking place in the US, the country will soon surpass Spain in terms of CSP deployment,” Hunter says. “As more intermittent resources are added to grids around the world, CSP’s unique capabilities will be even more valuable.”

The more intermittent sources added, the greater the need for the time-shifting storage that can be provided by CSP. But for the U.S. with its now slowing RPS, and the political demise of its loan guarantee program, this bump-up in renewables won’t be as fast as it could be.

Options?

The idea of a federal RPS has long raised hopes, more by opening the southeastern states that traditionally have eschewed renewable incentives, rather than raising targets for the 30 states that already have an RPS.

“A federal RPS would pick up all those states that have been not recognizing the advantages of clean energy,” Smith points out. “I think there’s about twenty that don’t. Most of those are more in the southeast. Georgia, Alabama, etcetera. There’s certainly a capacity to get solar into some of those markets. There really is no excuse for states to say that they can’t do solar.”

A federal RPS has been passed, in both the House, and the Senate - but of different congresses. However, it is unlikely that the two houses of the U.S. congress could agree on one any time soon.

“Exactly how that would be implemented remains somewhat uncertain, and some concerns remain on the intersection between state and federal standards,” NREL’s Ryan Wiser tells CSP Today in an email.

Financial calculus

But there’s still “the invisible hand of the market.” While natural gas is currently cheap, it has been very expensive in recent years. Hedging a bet on volatile natural gas prices with the safety of a set contract for solar should begin to make more sense to more utilities.

“Really the only options that utilities have right now are natural gas or renewables,” Smith opines. “Coal is very difficult to permit and not very cost effective when you look at cleaner coal technologies. Nuclear is not cost effective, and to get projects permitted is very, very difficult. Basically the options are natural gas or renewables.”

Some utilities are beginning to choose more clean energy beyond the mandates.

“Some utilities are seeing it’s cost-effective, and it’s popular with the ratepayers and regulators if they exceed their requirements,” he relates. “A few meet the RPS and that’s it. But some Colorado utilities have shown interest in going further than the RPS requirements, some in California.”

California is the only state that had early CSP experience. The Luz SEGS project has been reliably pumping out energy for thirty years. The California Energy Commission is now recommending an evaluation of a 40 percent or 50 percent standard by 2030.

Perhaps this just takes time. As the RPS leads more states to gain solar experience, as California has, similarly bold plans might emerge from these states too.
To comment on this article write to the author, Susan Kraemer

Or contact the editor, Jennifer Muirhead