The Union of Concerned Scientists has gone through the catalog of America’s coal plants, and found hundreds of mostly small, old, polluting, inefficient generating units that just aren’t worth operating any more, even on a purely economic basis. They looked at several different sets of assumptions, including different natural gas prices going forward, a price on carbon, whether or not the competing natural gas fired generation would need to built new, or whether it existed already with its capital costs paid off, and whether or not the production tax credit for wind ends up being renewed. In all of the scenarios considered, they found substantial coal fired generation that should be shut down on purely economic grounds, above and beyond the 288 generating units that are already slated for retirement in the next few years. They also found that some companies — especially those in traditionally regulated monopoly utility markets in the Southeast — are particularly reluctant to retire uneconomic plants, perhaps because they can effectively pass on their costs to ratepayers, who remain none the wiser.
Risk isn’t free; it’s a traded commodity with a price. Most prudent financial entities with a lot of exposure to the prices of natural resources try to manage unpredictable fluctuations in those prices by trading in risk. Producers worry about prices being too low; consumers need to protect against prices being too high. Risk trading (hedging) allows the two types of parties to share these risks, and so create a more stable market overall. Stable prices are good for business. You can plan around them in the long term, even if they end up being a bit higher on average.
In regulated electricity markets like we have in Colorado, fuel price risk often ends up being borne primarily by the rate payers rather than by the utility companies. In theory, state regulators ought act on behalf of the public (energy consumers) to accurately represent their tolerance of or aversion to risk in the resource planning process. Historically, the implicit assumption has been that the rate paying public is fairly risk tolerant, i.e. very little has been done from a regulatory point of view to avoid the potential detrimental effects of future fuel price volatility. This is a historical accident. Until recently, we didn’t have much choice in the matter. Of all the major sources of power available a century ago when we began electrifying society, only hydroelectric is similar in terms of its capital and operating structure to distributed renewables like wind and solar. All three have relatively large up front capital costs, and low ongoing operating and maintenance expenses. But for most of the time we’ve had electricity, most of that electricity has necessarily been dependent on fossil fuels, and so the question of whether or not customers wanted to take on the risk of future fuel cost fluctuations was immaterial. Fuel was the only option for expanding our electricity supply once we’d tapped the easily accessible hydro — if you wanted lots of power, it simply came with fuel price risks. This is no longer the case. Today, we have options that trade off between cost and risk, but so far as I can tell we haven’t done a good job of talking about the entire spectrum of possibilities. Broadly they seem to fall into four categories:
- Traditional fossil fuel-based power, that exposes rate payers to the full range of future price fluctuations.
- Capital intensive, fuel-free power like wind, solar, enhanced geothermal and hydro which have a range of prices, that are very predictable over the 20+ year lifetime of the capital investment.
- Fossil fuel-based power that is aggressively hedged, in order to protect rate-payers against future fuel price fluctuations.
- Fuel-free power with predictable future costs, combined with someone else’s fuel cost risks, which rate-payers would be paid to take on.
The first two options are the most commonly discussed. The third — hedged fossil fuels — is becoming somewhat more common, with some public utility commissions requiring the utilities they regulate to dampen fuel cost fluctuations. However, they generally do not require the utilities to hedge to the point where the risk profile of the fossil fuel option is similar to that of fuel-free power sources. This is what makes the fourth option interesting.
Minneapolis is Xcel’s home town, and a much bigger market than Boulder. The city is now talking about allowing their franchise agreement to lapse, in order to pursue more aggressive renewable energy policies than state law will allow if they’re served by the monopoly utility. The article gives a nod to Boulder’s votes over the last two years to explore the alternatives to franchise agreements, including the formation of a municipal utility. It’s great to see another much larger city looking at its options, and as far as pushing the overall utility business model to change, it’s great to see this happening within Xcel’s service territory. There’s a threshold out there somewhere, beyond which the current arrangement is no longer stable, and even the utility will start begging for something different. The faster we can get there, the better.
A presentation from Lawrence Berkeley National Labs, exploring Why Rooftop PV is so much cheaper in Germany than the US. Their feed-in tariff started out quite generous, and has declined predictably over the last several years, which has resulted in the rooftop PV market growing enormously, while installers have been forced to dramatically reduce costs. To the point where today, it’s about half the cost per-watt-installed to get PV in Germany that it is in the US. The physical hardware is the same price, but the process is much easier, and the businesses involved in it much leaner. Good old fashioned German engineering at work, but in the policy realm.
NREL took a nice long look at different ways to design feed-in tariffs (PDF) in July of 2010, based on the past decade’s worth of experience, both in the EU and several US states. It’s 144 pages long and aimed at policymakers… so, not exactly light reading. But if you really want to know how these things work (or fail), it’s great.
I just finished reading Renewable Energy Policy by Paul Komor (2004). It’s a little book, giving a simplified overview of the electricity industry in the US and Europe, and the ways in which various jurisdictions have attempted to incentivize the development of renewable electricity generation. The book’s not that old, but the renewable energy industry has changed dramatically in the last decade, so it seems due for an update. There’s an order of magnitude more capacity built out now than ten years ago. Costs have dropped significantly for PV, but not for wind (according to this LBNL report and the associated slides). We’ve got a much longer baseline on which to evaluate the feed-in tariffs and renewable portfolio standards being used in EU member countries and US states. I wonder if any of his conclusions or preferences have been altered as a result? In particular, Komor is clearly not a fan of feed-in tariffs, suggesting that while they are effective, they are not efficient — i.e. you end up paying a higher than necessary price for the renewable capacity that gets built. This German report suggests otherwise, based on the costs of wind capacity built across Europe. Are the Germans just biased toward feed-in tariffs because they’ve committed so many resources to them? NREL also seems to be relatively supportive of feed-in tariff based policies, but maybe this is because the design of such policies has advanced in the last decade, better accounting for declines in the cost of renewables over time, and differentiating between resources of different quality and utility.
Lawrence Berkeley National Labs has put out a report on the state of the wind energy industry, as of the end of 2011. I didn’t realize that the price trend had been so uneven over the last decade. The cost of wind power was dropping in the early 2000s, and then rebounded, peaking in 2008/2009 due to shortages in the turbine supply chain, before again dropping in the last year or two. I started looking into these prices because I’m reading a Renewable Energy Policy by Paul Komor (2004) and the prices he quotes ($40-$50/MWh) seem low, relative to the numbers from Xcel’s ERP and the recent bids I saw in Michigan (more like $60/MWh), but the book was written right at the wind price bottom. I’m also shocked at how wide the spread in costs is, even in just the last couple of years. California is paying $100/MWh for huge projects, and in the wind belt some projects are coming in more like $25/MWh. That’s got to be largely policy driven, and it indicates we’ve got a woefully inefficient market for wind.