For those of us in the power industry, media discussions of the economics of power generation reveal an almost complete misunderstanding of how power is priced. Depending on our vested interests, we may find this either frustrating or beneficial — but in all cases, it’s false.

Herewith I attempt to explain from whence the confusion arises — and why it is so critical for the clean energy community to understand this math and its consequences … and to more accurately articulate the economics of those options we prefer.

Costs, prices, and pro-formas

The cost of power, the price of power, and the number we stick in our pro-forma spreadsheets when we try to convince our investors to loan us the money we need to build a new power plant are all measured in dollars-per-megawatt-hour. All three are different, but most media coverage of the power industry — indeed, even language used by those of us in the industry — tends to conflate these three numbers, with confusing results.

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The cost of power is what it actually costs a given power plant to generate a unit of electricity. This is made up of four separate components: Fuel costs, non-fuel operating costs, capital recovery, and profit.

Fuel costs are fairly self explanatory, and are a function only of the fuel used, cost of that fuel, and efficiency of the power plant. For the most part, this is fully variable, in the sense that if my fuel costs contribute $30/MWh to my cost of generation, then a decision to curtail production by one MWh saves me $30.

Non-fuel operating costs are a little more complicated. Some non-fuel operating costs, like water treatment chemicals, are truly variable, just like fuel. Other non-fuel costs like labor are only a little bit variable, in the sense that I can adjust them over periods of months, but not moment-to-moment in response to plant output. Finally, some of these costs are fixed, like annual preventative maintenance.

Capital recovery is entirely fixed, and mathematical. If it cost me $50 million to build a power plant and my investors demand a 20 year payback, with 10 percent return on their money, I’ve got to pay them $5.9 million per year regardless of how much I spent on fuel, how often I operated, and how much I spent on maintenance. This number is the same no matter what I do and therefore has no impact on my variable price of electricity. Note, though, that if I include this value in my total cost per MWh, I am implicitly making a whole host of subsidiary assumptions, from total plant cost to interest rates to the number of MWh I will be able to generate in a year. It’s helpful to think of capital recovery on a $/MWh basis, but one must recognize that this is simply a convenient shorthand rather than a truly variable cost. (Try telling your bank that you owe them less money because your power plant didn’t run last month!)

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Finally, profit is fairly obvious. It’s as big as possible, of course. But it’s gravy, paid only after the fuel, maintenance, and capital recovery are covered. If there isn’t enough revenue available to cover all four buckets, the profit bucket is the first to be short-changed.

Now let’s look at the difference between cost, price, and pro-formas. If I add up my fuel, operating, capital recovery, and profit costs I get a number that tells me how much revenue I need to pay for my fuel, my employees, my maintenance, and my bank … and leave a little bit left in my pocket. When we go to our investors to build power plants, we build spreadsheets that show all the capital outlays and inevitably show that the price we will get paid for our power will be at or above our cost. If we do a good job of contracting and operating the power plant, this will happen — but it is by no means guaranteed.

So how is my price set? It all depends. If you are a regulated utility, you have the great luxury of knowing that the prices will be set to cover all your costs. Indeed, part of the responsibility of utility commissions is to ensure that the returns earned by a regulated utility are “sufficient to attract capital.” Take out the jargon and this simply means that the government structures prices to ensure that there is always enough revenue to pay out that “profit” bucket in the utility cost structure. This is why utility stocks have always been attractive to pension plans.

But for the rest of us schmoes, price is a lot less certain. Maybe we can sign a bilateral contract with a buyer (e.g., Joe agrees to pay Jane $70/MWh). Maybe we simply use this to displace the power we otherwise would have purchased from our utility, in which case any change to utility rates directly impacts the effective price I realize per MWh. Maybe I sell my power onto wholesale power markets, in which case my price is set at whatever level the market settles in at, with significant hour-by-hour volatility.

The interesting question to ask about price, though, is not what it is in some absolute sense (since non-regulated folks tend not to get absolute certainty on that question), but rather what price would convince me to shut down my plant. Basic economic theory and practice tells us that any business that has invested capital in the production of widgets — MWh or otherwise — will continue to produce those widgets so long as the price covers their variable costs. This makes sense. Let’s say you have a power plant that costs you $30/MWh for the fuel, $10/MWh for the fully variable operating costs $5/MWh for the not-so-variable operating costs and $40/MWh for capital recovery. Your total cost, exclusive of profit, is therefore $30 + 10 + 5 + 40 = $85/MWh. If you can sell that power for $90/MWh, you get to keep $5 worth of profit. But if your plant is built and fully staffed and the best price you can get is less than $85, would you take it? The answer is an unequivocal yes — so long as the price is above your $40/MWh fully variable price, because any number above $40 still gives you a little bit of cash to pay off your lenders and set aside money for upcoming maintenance. It may be less than you were hoping for, but it’s still better than nothing — which is what you get if you decide not to produce that hour.

The reason this calculus matters is because in modern wholesale power markets, there are hundreds of plants making hundreds of decisions every hour about whether or not to run, and the clearing prices on those markets has come to approximate the variable cost of the most expensive generator on the grid that is necessary to serve demand. Increasingly, this is a gas-fired turbine, but it’s a turbine owned by some cranky investors, who never get enough money to cover anything beyond their variable costs. This is why we saw the big fall off in new construction of gas plants after 2003 — investors no longer believed that the prices in those pro-formas were likely to match the prices they needed to cover their costs.

What this means for different power plant technologies

Now let’s divide the universe of all technologies into four buckets:

  1. Technologies with high variable costs and high capital costs
  2. Technologies with high variable costs, but low capital costs
  3. Technologies with low variable costs, but high capital costs
  4. Technologies with low variable costs and low capital costs

The first bucket is full of universally bad investments. They’re expensive to build and expensive to operate. As a general rule, no one is stupid enough to build those, although you do find many of them in R&D portfolios on the theory either that we’ll find a way to lower the capital costs and/or because of some external, non-economic benefit that convinces us that they may be in society’s long term interest. Natural gas-fired fuel cells are an obvious example.

The second bucket is full of all sorts of dangerously-tempting stuff. Cheap to build … and if the variable costs fall, you’ll make a ton of money. Of course, if they don’t, you’re in trouble, but many have been tempted to make that bet. This essentially describes the bulk of the centrally-located gas-turbine fleet in the U.S., and why it doesn’t run very much anymore.

The third bucket is where things start to get interesting. The U.S. power grid has long relied on this bucket (central-station coal and nuclear, specifically) to provide baseload power. You’d be a fool to build these plants if you didn’t first secure guaranteed equity returns, but that’s what our regulatory model is really good at. Note that these plants actually have very high costs, but since they are so cheap to operate on the margin, they tend to depress prices for power on the grid once they are built. The interesting point of comparison here is with renewables — specifically wind and solar — which also have comparatively high capital costs, but very low variable costs. We frequently talk about wind needing over $100/MWh to pencil, but this is a cost discussion, not a price discussion. You may need over $100/MWh to justify the investment in a wind turbine, but a grid dominated by such units will put downward pressure on the prices for power due to it’s low variable costs — just as nuclear and coal have done for decades. (Note that wind investors wouldn’t be happy if this happened, but that doesn’t make it a bad thing.)

The fourth bucket are the no-brainers, and are of course what my company, Recycled Energy, specializes in. What’s remarkable about the U.S. regulatory model is that it erects such massive barriers to technologies that fall in this bucket. Clearly it’s in our economic interests to change the paradigm.


As I’ve noted before, our current electricity regulatory model is biased heavily in favor of expensive capital deployment, and is essentially agnostic with respect to the variable costs of fuel. As we max-out the capacity of our existing power plant fleet, we are now entering a period where the decisions we make with respect to the next generation of power plants will have long-term implications — and will be heavily biased towards buckets one, two, and three above (e.g., centrally-generated power from coal, nuclear, and gas) unless we finally decide that it’s time to fix the regulatory paradigm.

Ideas on that to follow in my next post.

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