Price is not the only economic variable to consider in deciding what kind of generation a utility should build. Different kinds of power have different risks associated with them. This is important even if we set aside for the moment the climate risk associated with fossil fuels (e.g. the risk that Miami is going to sink beneath the waves forever within the lifetime of some people now reading this). It’s true even if we ignore the public health consequences of extracting and burning coal and natural gas. As former Colorado PUC chair Ron Binz has pointed out, risk should be an important variable in our planning decisions even within a purely financial, capitalistic framing of the utility resource planning process.
Utility financial risk comes largely from future fuel price uncertainty. Most utility resource planning decisions are made on the basis of expected future prices, without too much thought given to how well constrained those prices are. This is problematic, because building a new power plant is a long-term commitment to buying fuel, and while the guaranteed profits from building the plant go to the utility, the fuel bill goes to the customers. There’s a split incentive between a utility making a long-term commitment to buying fuel, and the customers that end up actually paying for it. Most PUCs also seem to assume that utility customers are pretty risk-tolerant — that we don’t have much desire to insulate ourselves from future fuel price fluctuations. It’s not clear to me how they justify this assumption.
What would happen if we forced the utilities to internalize fuel price risks? The textbook approach to managing financial risk from variable commodity prices is hedging, often with futures contracts (for an intro to futures check out this series on Khan Academy), but they only work as long as there are parties willing to take both sides of the bet. In theory producers want to protect themselves from falling prices, and consumers want to protect themselves from rising prices. Mark Bolinger at Lawrence Berkeley National Labs took a look at all this in a paper I just came across, entitled Wind Power as a Cost-effective Long-term Hedge Against Natural Gas Prices. He found that more than a couple of years into the future and the liquidity of the natural gas futures market dries up. In theory you could hedge 10 years out on the NYMEX exchange, but basically nobody does. Even at 2 years it’s slim!
Because of the split incentive described above, this isn’t so surprising in the regulated utility market — they’re not exposed directly to the fuel prices. But electricity generation only accounts for about 1/3 of the natural gas that the US consumes. Industrial uses (like making fertilizer with the Haber-Bosch process) are also about 1/3, and so is the combination of residential and commercial use (mostly for heating). It turns out these sectors also don’t hedge their fuel costs much, despite having better incentives than the regulated utilities. The first explanation that jumps to mind is that everyone — both the fuel producers and the consumers — have pretty high discount rates, so what prices do in the mid to long run doesn’t seem very important to them today. It might also be that while these other sectors of the economy consume a lot of gas, the gas makes up a smaller proportion of their overall operating costs, so their businesses are less sensitive to gas price fluctuations. According to Bolinger, in electricity generation, fuel is ~85% of the $30/MWh operating costs (with $4/mmBTU gas, in combined cycle gas turbines) — so marginal generation costs are almost indistinguishable from fuel costs. This is comparable to the cost per MWh for the best wind today, with the production tax credit in place. I.e. developments like the 200MW Limon II wind farm in NE Colorado which went for $27.50/MWh, substantially below the average PPA listed in the LBNL study:
This means Limon II makes economic sense even if all it ever does is displace the consumption of $4 natural gas, and Xcel has said as much publicly:
Whenever wind energy is generated from the Limon II facility, it will displace fossil-fueled energy on the Public Service system, mostly energy generated from natural gas. We think of this wind contract as an alternative fuel, with known contract pricing over 25 years that will displace fuels where the pricing is not yet known. That is the essence of the fuel hedge.
— Kurtis Haeger, PSCo (Xcel), 2012
In this case, the wind was basically a free hedge — no price premium was required to lock in a fixed price for 25 years. If that kind of pricing is available, it seems like it makes sense to build as much wind as can be physically integrated into the system. This is one end of the spectrum — price parity with the current marginal cost of fossil fuel generation, with guaranteed fixed energy costs from one source (wind) vs. completely unhedged fuel risk from the other (gas). Even if you don’t care about climate change or fracking at all that is still a powerful argument for investing massively in wind, and just using the natural gas as backup to fill in the gaps — i.e. gas firmed wind.
So, again, if we forced utilities to internalize fuel cost risks, what would they do? At least in relation to natural gas, so long as the PTC were in place, it seems likely that they would protect themselves from fuel price fluctuations by building a whole lot of wind, at little to no additional cost to the consumer. The above assumes that wind doesn’t get any credit for “capacity” — that it doesn’t decrease the amount of gas-fired generation you have to have on the grid — just in case it’s dead calm everywhere at once. That’s probably a little too harsh, so we might be able to save a bit on the capital costs of gas fired generation. But that’s where the utilities make their money, so it’s not surprising they’re arguing for giving wind zero capacity credit — so that no matter how much wind they build, they’re not required to take anything else offline or forego other investments in generation capacity — though they’ll probably end up operating those fuel-based resources a whole lot less.
Even without the PTC (which is worth about $28/MWh of revenue), a Limon II priced wind hedge would be in the money at around $8/mmBTU natural gas, a price which the futures markets (and EIA projections) consider plausible in the medium term.
I think a similar hedging argument could be made for energy efficiency investments vs. coal fuel risk. Efficiency is usually cheaper than renewable generation, has a relatively predictable fixed cost per unit energy demand avoided, and its constancy would match up well with displacing “baseload” coal power. And coal has nearly doubled in price over the last decade, so it’s hard to say there’s no fuel price risk to be concerned about.
Right at the end of 2013, there was another example of risk characteristics making all the difference in resource planning. A judge in Minnesota decided that distributed solar PV oriented to match summer demand peaks was a better deal for rate payers than peaking gas combustion turbines that would only be used about 1% of the time. On the basis of price alone the two options were very similar, but the PV had no fuel price risk going forward.
As with the Limon II wind farm and $4 gas, this is another no-brainer — it’s easy to see that two things with the same price and very different risk profiles aren’t both offering the same value proposition. By coincidence, both of these scenarios have offered regulators the opportunity to make risk adjusted price comparisons. But there’s no reason that this kind of thinking should be limited to cases in which prices happen to match up. Risk shouldn’t just be a tie-breaker — it’s a thing, all by itself, and it’s important. It’s worth paying more to reduce future uncertainty — how much more is a difficult question, but it’s clearly not zero. Google has been happy to enter independently into wind PPAs for electricity that’s more expensive than the wholesale rate today, because they want to know they won’t have to contend with high prices in the future:
We see value in getting a long-term embedded hedge. We want to lock in the current electricity price for 20 years. We are making capital investment decisions [regarding data centers] on the order of 15 to 20 years. We would like to lock in our costs over the same period. Electricity is our number one operating expense after head count.
We are less concerned about hedging our cash flows on a quarter by quarter basis. We are more concerned about the long term.
We are losing considerable amounts of money on every [wind] MWh [in the near term]. We just want to ensure the project is there in the later years.
— Ken Davies, Google, 2011
There are a lot of laws against “price fixing” and people get outraged when they think “price gouging” is going on. Maybe we should have similar rules about risk? “Risk fixing” and “risk gouging” — when price risks are offloaded onto an unwitting public that never signed up for them. Or maybe we should just ensure that risks end up haunting the decision makers that have the power to mitigate them.
It already makes very traditional economic sense to use renewables and efficiency to hedge against future fuel prices. Adding in any awareness of climate risk via a price on greenhouse gas emissions only makes the case that much stronger.
Revisiting the Long-Term Hedge Value of Wind Power in an Era of Low Natural Gas Prices by Mark Bolinger at Lawrence Berkeley Labs:
Mark Bolinger giving a presentation about the LBL paper:
- How Solar Beat Gas in Minnesota (Fresh Energy)