Could utility ratepayers be paid to accept fuel price risk?

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:

  1. Traditional fossil fuel-based power, that exposes rate payers to the full range of future price fluctuations.
  2. 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.
  3. Fossil fuel-based power that is aggressively hedged, in order to protect rate-payers against future fuel price fluctuations.
  4. 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.

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Minneapolis eyes way to push utilities to be greener

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.

Cost Effectiveness of Renewable Energy in Michigan

In the 2011 annual report to the state legislature on the cost effectiveness of Michigan’s Renewable Energy standard, it was revealed that wind bids have been coming in far cheaper than anyone expected they would.  In fact, even without the federal production tax credits, they’re far cheaper than new coal fired generation ($61/MWh for wind vs. $107-133/MWh for new coal).  Interestingly, Xcel’s 2011 resource plan lists the cheapest new generation option in Colorado as being natural gas combustion turbines… at $60/MWh.  So wind is cheap.  It’s also very low risk.  So how do we get more of it?

Discounting Fuels

It’s often been said that “time is money,” and it turns out to be more than an aphorism.

I’m going to try and tell you a story about discounting, which is one of the ways that we convert between time and money. The story has broad implications for the energy investments we choose. It’s not entirely straightforward, and if it’s going to make sense there are some background pieces you’re going to need. The background is important because the ending depends not only on understanding what is being done, but why. This story happens to be about Xcel Energy and Colorado, but the same thing happens in other places, with other companies, and in other contexts too.

To greens my argument may seem circumspect. I’m not going to challenge the doctrine of Everlasting Economic Growth. I’m not going to look at the large externalized costs of burning fossil fuels. I’m not going to argue against the monopoly electrical utility model. Those are important discussions to have — they’re just not the one I’m having here. What I’m trying to do is show that a minor change in the way we calculate the cost of future energy can drastically alter what kind of power we decide to invest in for the next century, even if we only look at the decision in selfish financial terms.

To the finance geeks among you, much of the background will be familiar, but the situation may seem strange unless you’re familiar with how regulated monopolies work. I haven’t been able to find anyone familiar with energy finance who thinks what we’re currently doing makes sense, but if you’ve got a thoughtful rebuttal, I’m genuinely interested to hear it.

Continue reading Discounting Fuels

Is an Energy Transformation Afoot?

SunEdison

Almost immediately after we empowered Boulder to form a utility, a spate of articles appeared in the national press talking about the relative costs of coal and renewables, and the trends in those costs.  There was Krugman’s Here Comes Solar Energy Op-Ed in the NY Times, making the case that solar PV is already cheaper than coal-fired power once you remove all the subsidies we provide to both of them, and calling for the Feds to fix regulation to make that clear.  Boulder’s own RMI had a bit of commentary on Krugman’s opinion: it’d be nice if Federal regulations were saner, but even without that fix, it makes sense to build this stuff now, and will only make more sense as time goes on and the balance of system costs (which currently make up 50% or more of the cost of a PV installation) are reduced through best practices, standardization and mass production.

From the industry side, GE’s Jeff Immelt also said that federal regulation was a little beside the point now… and that even without government support GE was going all-in, expecting something like 200GW of solar to be built in China and India by the end of the decade.  That’d be a non-trivial amount of generation, on the order of 10 Three Gorges dams, or as much power as the entire US nuclear generation fleet.  Meanwhile NRG Energy, a nationwide and largely traditional fossil-fuel based independent power producer is planning to spend the overwhelming majority of its capital investment funds over the next few years on solar, mostly small utility projects (20-100MW) and distributed rooftop generation.

In the same vein, Xcel Energy’s recently filed 2011 Electric Resource Plan foresees essentially no new generation facilities being built until close to the end of the decade.  Some of this is attributable to the soft economy, but many people are saying it’s just as much a consequence of energy efficiency, demand side management, and increasing distributed (behind-the-meter) generation coming on line.  Unfortunately, Xcel added a gigawatt of coal generation to its grid last year, and this lack of demand for more energy means the company is now walking away from the transmission lines that would have enabled large-scale solar-thermal with storage in the San Luis Valley.  This means that the only way to shift Xcel’s power mix in the near future will be to accelerate the retirement of existing coal-fired generation, making room for more efficiency, wind, and solar.

The optimistic narrative that falls out of the articles above — that our energy systems are undergoing a transformation — seems plausible, and I hope that it’s true.  Certainly it’s the one that the Boulder Light and Power effort is going to be built around.  It’s comforting to see that we’re not alone on the world stage, and less daunting to imagine our job as facilitating an ongoing transformation, rather than starting one from scratch.

Xcel backing away from solar-thermal enabling San Luis Valley transmission

Xcel appears to be backing away from new transmission lines to the San Luis Valley.  This infrastructure is required to implement the several hundred megawatts of solar-thermal generation that they proposed in their 2007 resource plan.  Solar thermal is the only renewable power (other than pumped hydro, which has limited availability) for which energy storage is potentially feasible right now (e.g. using huge tanks of molten salt).  It’s interesting to contrast the utility’s statements on the San Luis Valley project with what they’re saying about the Pawnee retrofit, and what they said about the Comanche 3 plant.