Last January, Rep. Ed Markey (D-Mass.) convened hearings on the ways allocation of CO2 permits under a cap-and-trade system will impact power prices and utility profit margins. The short version, drawn from the evidence of Kyoto and other systems that have given credits away for free, is that while free allocations lower power prices in theory, in reality prices rise just as much as they would otherwise — but they increase margins for exempt generators (i.e., coal plants). Indeed, one of the great criticisms of the Kyoto Protocol has been that it has directly led to increased profits for Europe’s old coal plants.
Since then, there has been a growing chorus from (coal-heavy elements within) the electric sector arguing that utility regulations compel them to pass along any operating savings to the rate payers — and therefore, that free allocations really do ensure lower power costs. (See here for more details on the “pass-throughs” innate to modern utility regulation.)
So on the one hand, we have the paper trail from Kyoto, and on the other hand, we have what would appear to be a pretty robust theory based on modern utility law. Who’s right?
The short version: facts on the ground trump theory. The longer version is below the fold.
Picture a 2×2 matrix. On one axis, put the theory of utility law and the practice of utility law in two separate boxes. On the other axis, put regulated utilities and unregulated utilities.
The theory that free allocations bring benefits exclusively to rate payers is true in only one box on this matrix: the theory/regulated box. As you might imagine, all of reality lies outside the theory column. But also, an increasing number of our nation’s power plants lie outside the regulated space. Let’s look at each of these in a bit more detail.
Regulated vs. unregulated generators
To the best of my knowledge, there is no one in the pro-free-allocation camp who argues that the allocation of carbon credits should apply only to regulated power plants. So what happens if the go to deregulated (or less-regulated) plants?
The National Regulatory Research Institute identifies 16 states (plus the District of Columbia) as having “fully restructured” their electric industry. The structures vary from state to state, but to a broad degree, these states (Ariz., Texas, Ill., Mich., Ohio, Va., Del., Md., Pa., N.Y., N.J., R.I., Mass., Conn., N.H., and Maine) allowed upstream, wholesale generators to compete against one another and kept traditional regulatory controls on the distribution utilities. As a result, many of these states have old power plants with high carbon/MWh signatures (e.g., central-station coal) that would receive a huge economic boon under any free allocation approach.
To understand why, recognize that the free allocation of a CO2 permit is simply a gift. All new plants would have to factor the cost of CO2 emissions into their economic calculus, but the old, dirty plants would get it for free. In a restructured market, that means those grandfathered plants would suddenly find themselves with a dirty asset that got a clean premium. Presto! More profits for the old, dirty guys, solely based on the fact that they’re old and dirty. (One of the perversities of a free allocation model is that the older and dirtier you are, the bigger your gift, since the allocation is inevitably based on historic emissions profiles.) This, in a nutshell, is why Kyoto has proven to be so profitable for European coal plants.
But here’s the most important statistic: In 2005, the total generation in those 17 deregulated regions was just shy of 1.6 billion MWh — or about 48 percent of all the generation in the U.S. If we make a decision based on the assumption that all power plants operate under a traditional regulatory model, we are essentially ignoring one-half of our power fleet. Even before we get into a discussion about the theory versus practice of regulated power plants, the argument that free allocation is good because utilities must share all cost savings with their consumers is bogus.
The theory vs. practice of rate design
Now let’s look at the other slice: regulated utilities in practice. In theory, modern utility rate law works as follows: a utility goes to their commission and says, “I need to invest $X of capital in generation plants, wires, and pipes, and they will have an annual operating cost of $Y/year.” The commission reviews that analysis, vets the numbers, and makes a decision as to whether that investment is “prudent.”
(“Prudence,” among other things, commonly implies that the utility has taken a “least cost” approach to serving new load and is not building expensive power at the expense of cheap power. One doesn’t have to spend much time looking at historical capital allocations in the regulated space to realize how far this particular theory differs from reality.)
Presuming the investment meets commission approval, the commission then calculates the returns the utility is allowed to receive on that capital investment. This sets an annual revenue goal for the utility — but the operating costs are all passed through, with no margin.
Let’s look at an example: Suppose a utility wants to invest $100 million in a power plant which will cost $10 million per year to operate. Suppose further that the commission determines this investment warrants a 9 percent return on invested capital over 20 years to justify the risk. That requires $11 million/year to pay off the capital, plus the $10 million in operating costs. Ergo, the utility gets ($10 + $11 =) $21 million per year in revenues.
Now, no one pays the utility $21 million. Rather, this revenue target gets divided by the anticipated kWh sales to determine how much the utility rate payers are going to pay per unit of service. And now we start to differ pretty substantially from utility theory:
- Not all customers pay the same price for power, which means that some customers will pay disproportionately for the utility profits.
- Annual kWh sales will differ from the projected number, giving the utility greater or lesser returns. (This is why utilities have historically been so hostile to energy efficiency investments that reduce their kWh sales.)
- Lots of capital investments will be made over time and lumped into a given rate case. Actual capital costs may vary from the stated levels.
- Not every capital investment gets a full rate case. Indeed, it is pretty common practice for utilities to ask for “partial” cases to cover specific investments. (This is usually a sign that they really like their broader rate structure and don’t want it exposed to full commission review.)
(For those of a particularly wonky bent, see here (PDF) for a more thorough review of modern utility rate law.)
Now watch what happens. Utility X files for a rate case and gets new tariffs in place. Theoretically, they only make their money on capital costs — operating costs are pass-throughs. But even if they accurately predicted all capital costs and operating costs, there is a pretty good chance that next year won’t be exactly like this year. In many cases, one finds that utilities go many years without a full rate case (more than 10 is not uncommon).
Why would they do this? Because they like their rates. If you can earn returns on capital and then steadily increase kWh sales without investing new capital, your returns will steadily rise. And if you suddenly find yourself with greater operating margins (say, because you just got a big fat free allocation of CO2 permits), why have your rates reset to reflect that cost? You’d be giving money away.
That’s not to say that the utility commission won’t eventually get around to pushing for a rate case on their own, but here’s the dirty little secret of modern rate making: utility commissions don’t like rate cases. They’re a lot of work. They’re politically dangerous, since they run the risk you might have to raise rates. Utility commissions are almost universally understaffed and underpaid. And utilities have learned how to exploit this to their advantage, to defer rate cases and keep excess returns as long as possible.
What it all means
No matter what you hear, free allocation of pollution permits is a huge gift to our nation’s coal utilities. It won’t lower power prices, but it will increase the profit margins of anyone fortunate enough to be on the receiving end. And it will sustain operation of our most carbon-intensive power sources, deferring the point at which we finally begin to get serious about greenhouse gas abatement.
In short: auction.
