Great questions. The simple answer to all of them is that the devil is in the details, many of which are still to be sorted out. Herewith a somewhat more rigorous response:

1. The idea of the exclusion from other incentives is only to blunt any political pushback that 80% of avoided power cost + incentives = a net societal increase in the cost of power. As a practical matter, I would not assume that this necessarily means an exclusion from other payments that are tied to direct financial value. (e.g., if you sell capacity or power factor correction to the grid, you should still be paid to do so, for simple reasons of economic alignment.) So too with GHG. The challenge of course lies in figuring out which incentives are just incentives and which are tied to a specific, monetized action on the part of the generator. (Sadly, the state provides blurry guidance on this – as we’ve seen from the debate over how RPS payments ought to be offset against GHG credits.) Bottom line: the spirit of the rule is easy. The letter is hard to write.

2. Couple responses: first, note that this isn’t a carbon standard per se, and there is no reason why the a technology could not be paid under a GHG rule but not be eligible for the CESOP. (Indeed, note that a fossil-efficiency standard doesn’t translate directly to carbon, since it doesn’t account for the carbon content of different fuels.) Second, the efficiency test is a matter of precedent and politics. The precedent is the 1978 PURPA law, which included a 45% efficiency threshold to be eligible for payments for 100% of the utility’s avoided cost (although that was widely taken – inaccurately – to be the competing cost of generation, treating the wires as free). Thus, the politics of the CESOP are expressly designed to counter anyone who didn’t like PURPA by saying that the efficiency standard is higher and the payment is lower (80% vs. 100%). At core though, this is about efficiency, not carbon (although the two are certainly linked.) All that said, your point is valid, and one could imagine a variant with payments ratcheting up with efficiency (e.g., 60% for a 5% efficiency improvement, 61% for a 10% improvement, etc.) It would be intellectually elegant, but awfully complicated – we opted for (slightly) intellectually sloppy simplicity, but we’re open to suggestions to revise.

3. It’s a good question, but to a certain degree the CESOP dodges the concern. Since the calculation done by the regulator at the start is a competing cost of baseload power, any MWh sold under the CESOP avoid the need to build that baseload. Clearly, when the generation runs it may displace a differential price off the grid, but that’s a marginal calculation that is sideways to the goal of the CESOP: namely, to make sure that as we enter the current build cycle, we build the right stuff. The alternate central-station plants are way more expensive than the marginal power on the grid since those still have to amortize all their capital – while the marginal MWh on the grid is whatever a plant can sell it for at a profit (essentially, any thing greater than their fuel cost). Building expensive new generation eventually drives up the marginal cost, but there is a lag – the CESOP, by pricing against that alternate all-in cost creates a time-shift of that lag forward, such that the time-of-use pricing is less important. That said, per comment 1, I’d expect that a generator that can provide benefits beyond power – line loss reduction, VARS support, voltage stabilization, etc. – would be able to be compensated for same, and these values tend to be higher on-peak, providing some additional revenue streams to those generators that can operate during those hours.

4. You’re absolutely right. Note thought that a CESOP isn’t guaranteeing cheap debt. It’s simply levelling the playing field as it relates the utility’s unique ability to obtain what are in effect, long-term contracts with a triple-A credit customer (the state). The debt a CESOP-user can obtain will still factor in all the other variables, from technology risk to management team, and may or may not end up with debt costs that are the same as the utility. But this at least removes the artificial advantage the utility has for the lower bps they can obtain solely by virtue of their guaranteed, high-credit off-taker.

Four quick questions about your CESOP model, which I generally like a lot. Please don’t read my questions as an attack, as I am sympathetic to the model, as well as to what RED is trying to accomplish. From what I understand about RED, I am a big fan.

1. Do you contemplate including (or excluding) the net cost of carbon credits or taxes (whether under a cap-and-trade system, a carbon tax or something similar)? I guess I assume that the answer to that question is inclusion, but … Or does declining other “state and federal initiatives” mean declining the advantages of C&T credits, for example?

2. The 50% standard for fossil fuel consumption per MWh (compared to US grid average) was the only part of your plan with which I disagreed. Shouldn’t inclusion of net costs (or credits) from a cap-and-trade or carbon tax system deal with that goal nicely? If a project only hits a 60% standard (rather than 50%), then its carbon tax or credit differential would account for that aspect, if you see what I mean. And a project which hits a 40% or 30% goal would get “extra credit.” Setting a 50% standard seems a little Stalinist- why should a great project that only hits 51% be knocked out of your program?

3. What about the intermittency issue for renewables? How does your model price in the costs of intermittency and/or peak non-availability?

4. Lastly, while I share your frustration at the advantages that utilities (and centralized, fossil fuel plants) have as to cost of capital, those advantages (to the extent that they are solely the result of economies of scale) are mostly real, not contrived or the result of utilities regulation. I spend most of my professional life trying to help privately-held companies (mostly outside the energy field) access the capital markets in various ways, so I am keenly aware of the fact that bigger or lower-risk enterprises have lower costs of capital than smaller or weaker ones. It’s true across the economy, and reflects real costs and risks for investors, mostly not regulation. Capital costs for smaller or less well-capitalized enterprises are higher, and for good reason. Somehow, your model has to address the reality that lenders or securities purchasers effectively run higher costs, or incur higher risks, or both, in providing capital to a venture which delivers a 10MW solution than one that delivers a 1 GW solution. Those higher costs, or risks, are like gravity (you can complain about them, but they are real, and they ain’t going away). I have no answer for you, but I am just pointing out a reality.

Anyway, keep up the good work.

Thanks.

Pete

Fair criticism, to which I’d simply differentiate between near and long-term strategy. In the long-term, we absolutely must unpack the electric utility regulatory model that constrains innovation and protects the status quo. But the nature of this current moment in our planning process is that we are about to deploy massive amounts of capital in generation assets, which we have a responsibility to do more sensibly. We will not fully deregulate in the next 2 – 5 years. But we might be able to make a few smaller changes that have a big material impact on the generation mix for decades to come.

Of course our long-term goals remain the same. But we have an opportunistic moment to seize a significant victory that – while not the end-game – pushes us in the right direction, and makes meaningful changes to the system even if we cannot achieve total regulatory reform.

Your proposal seems to make sense, but I wonder why, especially in light of your criticism of the nation’s current electric regulatory model, you want to maintain the status quo of regulators and utilities. Haven’t these two actors been the key blockers of alternative energy development? Why don’t you lean more towards competition?