This blog was written by John D. Wilson, former Deputy Director for Regulatory Policy at the Southern Alliance for Clean Energy.Guest Blog | September 1, 2016
The US Energy Information Administration (EIA) raised an interesting point in a new report, but I think they have missed the key point. EIA suggested that the reasons that North Carolina solar developers tend to use PURPA contracts is their relatively advantageous terms and apparently satisfactory rates. While there is merit to these points, EIA has missed a key factor: the design of North Carolina’s Renewable Energy Portfolio Standard.
For those who are curious about what PURPA is, I wrote a blog back in 2011 that discusses this in general terms (not specifically related to the solar market). But fair warning, PURPA is pretty complex for those not really familiar with utility regulation. However, understanding PURPA is the key to understanding which private market ideas can actually get built and deliver electricity to customers in the Southeast.
Below, I will explain just how the design of the NC-REPS law drives the result EPA illustrates in the graph at right. But there’s a clue that it isn’t North Carolina’s PURPA contracts right there on the graph: North Carolina accounts for fully one-third of the solar capacity designated as being paid for power under the PURPA statute. Unless North Carolina’s regulators are exceptionally generous to independent power producers (and they aren’t), then something else is going on here. Otherwise there would be a few other states with strong PURPA-driven solar development.
While many states have renewable portfolio standards, what I believe is (relatively) unique to North Carolina is that the NC-REPS law has a cost recovery framework that is built around the avoided cost rate. For those readers who aren’t practitioners of utility regulation, “cost recovery” is regulatory lingo for “specifically how much, who and with what tools the utility gets to bill customers to get its money.”
Under NC-REPS, avoided costs are recovered in one tariff (a legal document that connects cost recovery to customer bills) and the remaining revenues needed for renewable energy are recovered in another tariff. So regardless of whether the project is contracted under PURPA or not, the costs have to be split up into two buckets, PURPA and “all the rest.” It is literally extra work for everyone involved to NOT use the PURPA rate in North Carolina.
In many other states, the entire cost of a renewable energy contract is administered through a single tariff, which might be the PURPA QF rate tariff or perhaps by assignment to specific types of customer rates. (Yes, I am oversimplifying here but generally I think North Carolina is unusual in splitting cost recovery into two parts.) Thus, outside of North Carolina, where a PURPA contract is used, the PURPA rate likely represents the entire payment from the utility to the owner of the solar facility. It is, in fact, remarkable that half of the solar power contracts outside of the top four states are contracted under PURPA.
Power purchase agreements with “nonqualifying facilities” are often heavily influenced by the PURPA rates as well. Whether or not a potential qualifying facility actually chooses to contract as a “QF” depends on a number of factors that don’t necessarily represent an improvement over the QF terms available to the solar developer. The QF terms and rates represent one point among a range of potentially “fair” contract outcomes, some of which may be higher or lower rates, and some of which may be longer or shorter terms. While the PURPA rate and contract duration in North Carolina is better than some other Southeastern states, in my opinion North Carolina does not reflect the best practice in bringing forward the very best value for North Carolina utility customers.
One final point about NC-REPS. It is my impression that the structure of the NC-REPS compliance framework and North Carolina tax law combine to result in North Carolina utilities using credits, rather than direct project ownership, to comply with NC-REPS. This also reinforces the use of PURPA QF contracts.
So here is the bottom line: EIA is looking to the way that North Carolina implements PURPA to explain the heavy use of PURPA in that state, but in fact it is the structure of an entirely different law and regulation that I believe is the main reason North Carolina solar developers use PURPA.
The North Carolina market helps show that going above the PURPA QF rate may not mean higher costs. Just because customers are billed for costs (in the “REPS Rider”) that are above and beyond the costs billed to cover North Carolina PURPA rates, that does not mean that the additional costs represent an increase in customer rates. The most comprehensive study of NC-REPS (which is not available from North Carolina Energy Policy Council’s website anymore) was unable to measure the rate impacts. Furthermore, in responses to discovery questions we have filed, Duke Energy does not “look back” to see what actual experienced avoided costs were in any given year compared to the forecast. So it may be that avoided costs over or under estimate actual cost savings resulting from the solar projects. When looking at other utilities’ confidential analyses of this question, I am pretty sure the answer is that PURPA avoided costs underestimate the savings associated with solar power purchase agreements.
One thing we do know is that the economic benefit of these projects has been very large, estimated at $1.7 billion to North Carolina, with 21,163 job-years during 2007-2012 alone.
And while I’m on the subject, one general problem with PURPA rates is that they are collected entirely through the fuel recovery rider in most states. This is an energy-only charge – makes sense for small customers, but for large customers it means they are paying for capacity through the energy charge rather than through the demand charge. It can create some resistance to increasing PURPA and other PPA costs.