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.
Risk has value — negative value. You can pay to get rid of it, or you can be paid to accept it. The Colorado PUC allows Xcel Energy to spend up to $0.91 per million BTUs of natural gas to mitigate fuel price volatility (this is the Gas Price Volatility Mitigation adder or GPVM if you want to read more about it…). That’s nowhere near enough to lock in a long-term multi-decade supply contract at a fixed price, which is what you’d need to do to make the risk profile of natural gas similar to that of wind and solar, and thus make their risk-adjusted costs directly comparable. That kind of long-term supply contract doesn’t really exist on the open market today anyway.
Nevertheless, the GPVM adder does reduce the fuel cost risk that Xcel’s rate payers are exposed to. There’s an implied risk tolerance encapsulated within that price — the $0.91 per million BTUs — a judgement on the part of the PUC about how much it’s worth to the utility customers to avoid a given amount of fuel price risk. It’s apparently the PUC’s determination that rate payers aren’t willing to pay all that much to ensure stable rates in the long run. I might disagree, but ultimately it’s a value judgement, and it’s hard to say conclusively that one risk tolerance is right or wrong. As with all future costs, our present valuation of future fuel price risks hinges sensitively on our choice of discount rate.
Given a particular determination of customer risk valuation, we can look at different ways to obtain a portfolio of generation resources which reflect that valuation, and compare them to see which is the most cost effective. In this context, you can look at the relatively high cost of renewable energy as being a function of their extremely conservative risk profile. Renewable energy is to a well diversified generation portfolio what US Treasuries are to a well diversified investment portfolio — you don’t buy them because you want to get rich quick (that’s what Vegas is for). You buy them because they help to stabilize the overall performance of the portfolio; they’re risk mitigation tools. If pure renewables seem too expensive, and more conservative than you need them to be financially, they can be mixed with fuel-based power to create a generation portfolio with less volatile overall costs than fuels alone, and lower overall costs than renewables alone. Alternatively, if we care about the greenhouse gas emissions associated with our power system, we can go with pure renewables for our actual generation resources, and sell our resulting underutilized risk tolerance into the fuel futures markets. This would effectively reduce the cost of renewables and allow us to create a generation portfolio that matches our risk tolerance, regardless of its GHG emissions properties.
Selling the service of accepting someone else’s fuel cost risk would of course facilitate the continued burning of fossil fuels, but it would allow us to in the short run obtain whatever risk profile we wanted without dedicating our own capital infrastructure to the burning of those fuels. That might make it easier to revise our risk tolerance downward in the future, by unloading the contracts onto another party in the risk markets. Compared to a coal or gas fired power plant and the attendant commitment to decades worth of fuel purchases in the service of a sunk capital cost, paper risk is relatively liquid, and easily transferable.
No matter how you assess utility customer risk tolerance, it’s not in their best interest to avoid pricing risks. If you think they’re risk averse, then you need to know how much fuel risk to shed, and you need to incorporate the cost of doing so into the overall cost of fuel based power options. If you think they’re risk tolerant, then you need to know how much that tolerance is worth to others — whether it’s worthwhile for the customers to take on the risk directly, or cheaper to use low risk generation options and sell the risk tolerance off. What we do now is to largely leave fuel risk unpriced.
Furthermore, given how competitive wind has become already, if the fuel price risk it allows a utility to avoid were appropriately monetized, I would be pretty surprised if it didn’t come out as the cheapest generation option overall. Today a predominantly wind powered grid would need enormous dispatchable capacity to firm it. It would be interesting to see what the trade-offs look like within a diversified renewable/efficiency/demand/gas portfolio (wind + solar + demand response + efficiency + enhanced geothermal + dispatchable gas) if one took into account monetized fuel price risks in addition to avoided capital and fuel costs.
- Utility-Scale Wind and Natural Gas Volatility (PDF) by Lisa Huber at the Rocky Mountain Institute.
- Practicing Risk-Aware Electricity Regulation (PDF) by Ron Binz, former Chair of the Colorado Public Utility Commission.