Retooling Energy Regulations: Who Decides?

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On July 16, 2020, the Federal Energy Regulatory Commission (FERC) revised its regulations governing qualifying small power producers and cogenerators under the Public Utility Regulatory Policies Act of 1978 (PURPA). PURPA was designed to reduce demand for traditional fossil fuels by encouraging the development of these small power producers and cogenerators.  Yet, as regulation-mandated PURPA contracts expanded, many utilities (and ultimately, ratepayers) became saddled with expensive power contracts that over-charged for energy and were unnecessary.  The new rule provides some added flexibility to state regulators and makes other changes designed to modernize PURPA. Join Anthony T. Clark, Senior Advisor at Wilkinson Barker Knauer LLP and a former FERC Commissioner, and Travis Kavulla, Vice President for Regulatory Affairs at NRG Energy and former commissioner at the Montana Public Service Commission, to discuss the new PURPA rule and its potential implications for the energy market.

Featuring: 

Anthony T. Clark, Senior Advisor at Wilkinson Barker Knauer LLP and former FERC Commissioner

Travis Kavulla, Vice President for Regulatory Affairs at NRG Energy and former commissioner at the Montana Public Service Commission

Moderator: Adam Griffin, Constitutional Law Fellow, Institute for Justice

 

This teleforum is open to the press - please dial 888-752-3232 to access the call.

Event Transcript

[Music]

 

Dean Reuter:  Welcome to Teleforum, a podcast of The Federalist Society's Practice Groups. I’m Dean Reuter, Vice President, General Counsel, and Director of Practice Groups at The Federalist Society. For exclusive access to live recordings of Practice Group Teleforum calls, become a Federalist Society member today at fedsoc.org.

 

 

Greg Walsh:  Welcome to The Federalist Society's Teleforum Conference call. This afternoon's episode is titled, "Retooling Energy Regulations: Who Decides?" My name is Greg Walsh, and I am Assistant Director of Practice Groups at The Federalist Society.

 

      As always, please note that all expressions of opinion are those of the experts on today's call.

 

      Today, we are fortunate to have with us Tony Clark, a Senior Advisor at Wilkinson Barker and Knauer and former FERC Commissioner, Travis Kavulla, a Vice President for Regulatory Affairs at NRG Energy and former commissioner at the Montana Public Service Commission, and moderating is Adam Griffin, a Constitutional Law Fellow at the Institute for Justice.

 

      After our speakers give their opening remarks, we will go to audience Q&A. Thank you all for sharing with us today. Adam, the floor is yours.  

 

Adam Griffin:  Thanks, Greg, and thanks to everyone for being on this call today. We have two excellent speakers on today's Teleforum to discuss an important new rulemaking from FERC, the Federal Energy Regulatory Commission.

 

      The final rule revises the Commission's regulations, implementing the Public Utility Regulatory Policies Act of 1978 or PURPA. PURPA was enacted under the Carter administration to reduce demand for traditional fossil fuels by encouraging the development of small power producers and cogenerators called qualifying facilities or QF.

 

      This occurred by placing certain requirements on utilities for how they had to treat QFs entering the market, including mandating the entering into certain contracts to buy QF energy as well as to buy QF capacity. Capacity, in the industry, is the ability to produce energy when in greatest demand.

 

      Yet, as regulation mandated PURPA contracts expanded, many utilities and ultimately ratepayers became saddled with expensive power contracts that overcharged for energy. The new rule's stated purpose is to better align those regulations with the modern energy landscape while continuing to encourage development of qualifying facilities called QFs.

     

      A quick rundown of the major changes and then I'll turn it over to our speakers. The new rule allows states to approve contracts between utilities and QFs that have variable energy compensation rates. The old rule required six rates per energy during the life of the contract. The new rule also allows state regulators to use competitive solicitations to set QF breaks for both energy and capacity instead of relying on administrative pricing.

 

      The new rule requires utilities to purchase from QFs that generate five megawatts of power or less and the regional wholesale markets that exist in two-thirds of the United States. This is a reduction from the old rule which required utilities to purchase from QFs that generated 20 megawatts of power or less.

 

      The new rule also modified purpose one-mile rule. The one-mile rule determines whether separate facilities are considered to be the same site. If facilities are within one mile of each other, they are a single facility. If facilities are more than one mile apart but less than 10 miles apart, then parties can contest and prove that they are still a single facility. Facilities ten miles apart or more are separate facilities.

 

      The new rule also requires states to create criteria that a QF must satisfy before it is entitled to a contract or a legally enforceable obligation with the utility. Finally, the new rule allows an entity to freely protest the certification or recertification of a QF, where the old rule charged entities $50,000 to do so.

 

      To provide insights into the new rule, its implications and impact, The Federalist Society is pleased to host two energy law experts. First, we will hear from Tony Clark. Mr. Clark is a Senior Advisor at Wilkinson Barker Knauer LLP. He is a former FERC Commissioner, a Chairman and Commissioner of the North Dakota Public Service Commission, a former president of the National Association of Regulatory Utilities Commissioners, a former labor commissioner of North Dakota, and member of the North Dakota House of Representatives. Mr. Clark is a recognized thought leader in the world of energy law, and we are grateful that he joins us today to provide his insights on FERC's new PURPA rulemaking.

 

      After Mr. Clark, we will hear from Travis Kavulla. Mr. Kavulla is the Vice President for Regulatory Affairs at NRG Energy Inc. Mr. Kavulla previously headed up energy and environmental policy for the R Street Institute, a pro-liberty think tank and before that, was twice elected to public office as a utility commissioner in Montana. Mr. Kavulla has also held leadership roles in national policy circles including as president of the National Association of Regulatory Utility Commissioners and a co-author of NARUC's whitepaper on PURPA reform.

 

      Thank you, Mr. Clark and Mr. Kavulla, for being here today. I'll turn it over to Mr. Clark to begin.

 

Anthony T. Clark:  Well, thank you, Adam, and thanks to The Federalist Society for hosting this timely topic and an important one in the energy world. Just a couple of opening comments on the PURPA rulemaking and things to consider in why FERC did what it did. And then we'll look forward to hearing from Travis and engaging in some Q&A.

 

      First of all, it's worth noting that in terms of FERC's ability to shape PURPA, there are some limitations around it, which is that, as we all know, as an administrative agency, it still has to live within the statute itself. So some of the concerns that you sometimes hear from state regulators or utilities or consumer groups about how PURPA was working or being enacted or, really, even the original intent of PURPA, is really embedded in the statute itself. So FERC's ability to shape it around the edges is limited, understandably, by the statute itself.

 

      But having said that, the Commission does have a fair amount of discretion to ensure that it's implemented along statutory guidelines but in a way that works given the energy marketplace as it is. And the Act itself envisions the Commission from time to time doing exactly what it did here.

 

      Now, this is a long-term process. The opening of the rulemaking and the gathering of the information started back, I think, as far as 2015. It was while I was on the Commission, and we had some initial factfinding technical workshops at that point. And it was really the culmination of hearing, probably for the last 10 or 15 years, from a lot of states that were having a great deal of concern about PURPA and what the impact was on consumers.

 

      And in some ways, I think there has always been a little bit of a disconnect between how people perceive PURPA in certain regions of the country and in other regions of the country. And it really breaks down along a few lines. When I talk about this disconnect, I'll give you an example of just my own working career and the different perspectives that I had on PURPA throughout my time in regulatory agencies.

 

      I spent about 11 and a half years on the North Dakota State Commission and about four and half years on FERC. Now, North Dakota is an upper Midwest/somewhat Western state that has vertically integrated utilities. But it's a state that all of the vertically integrated utilities are within an organized RTO.

 

So when you combine the fact that the investor and utilities were within an RTO and a lot of the just geographic base of the state was in non-jurisdictional co-ops, you really didn't have that many PURPA projects that were being developed there. And that is the case in a lot of parts of the country.

 

And so in my time at the state commission, I really didn't hear that many PURPA case. Every so often, with our utilities, we would set the avoided cost, but it was a proceeding that didn't have a huge impact on consumers because there just weren't that many projects that were out there.

 

When I got to FERC, I started hearing a lot about PURPA, especially from states to the west of North Dakota. So the PURPA issue is an especially big issue in parts of the southeast and in much of the west where the utilities are in bilateral markets and not in organized markets. And in these states, the impact that PURPA was having was dramatic. And we were hearing directly from state commissioners.

 

I'll give you two examples that I think are instructive of utilities that have faced a lot of issues with PURPA, one from Idaho, Idaho Power, and one is northwestern, at least in terms of its Montana jurisdiction.

 

To give you an idea of the impact -- and I think, again, people in other parts of the country may not quite appreciate how big an impact it is. Idaho Power, it's got under 600,000 electric customers. When you total up customer obligations for all PURPA generation projects, it's about $3.3 billion for those 700,000, roughly, customers.

 

PURPA generation contracts have averaged about 14 percent of Idaho Power's total generation but 33 percent of their annual generation costs the last five years. And on average, it was PURPA projects were costing something like two to three times higher than any other system resources. But nonetheless, because it was a statutory obligation and because of the way the pricing rules that FERCA had established, this was the net result in Idaho.

 

Turning to Montana -- in the spirit of full disclosure, I serve as a member of the board of directors of Northwestern Energy, which is the largest IOU in the State of Montana. But if you look at -- this is as of last year, so this data's probably a little bit changed. But as of last year, if all of the PURPA projects that were proposed were to come online by 2022, that would be about 1245 megawatts just from PURPA projects.

 

In comparison, Northwestern's total rate-based assets are under 900 megawatts. And the average retail load in the entire state is about 750 megawatts, which gives you an example of the idea of the magnitude that this has. But here's the kicker, and this is the real issue.     

 

Northwestern has a capacity deficit of about 645 megawatts. In other words, there's a lot of energy at given points during the day, but in terms of actual deliverable capacity, there's actually a short fall. But all of those PURPA projects that are proposed do very little to accomplish anything in terms of alleviating that capacity short fall.

 

So when you look at the magnitude of the problem in some of these often times smaller states, I would argue that if you had a proportional cost problem as big as this, say, in the heart of PJM, I think it would've been an all hands on deck, the house is burning down, FERC has to deal with this issue immediately.

 

If it had happened in a part of the country that just gets more visibility on some of these issues, I think because it was happening out in flyover country, it probably languished a little bit. But I'm very glad that the Commission addressed it and I think in most ways did a pretty good job of trying to coordinate the requirements of the statute with the rulemaking flexibility that it had.

 

What it does is, I think, and it helps correct some of the myths, I think, that sometimes exist about PURPA, two of the biggest ones being that PURPA is necessarily always good for the environment and for most just clean energy projects. And the second is that PURPA necessarily injects competition and therefore cost savings for consumers.

 

As to the first point, one of the interesting things -- taking again, for example, the Montana situation, PURPA projects aren't necessarily just renewable projects. In the case of the Montana system, there are two projects called CELP and YELP, Colstrip Energy Limited Partnership and Yellowstone Energy Limited Partnership. These are qualifying facilities under the statute and are contracted and have been for a long, long time.

 

One is a waste coal generator. One is a waste petcoke generator. They produce about 11 percent of the energy in the Montana system, and they produce about 37 percent of the Co2 emissions on the Montana system. So I think we should disabuse ourselves with the notion that PURPA's always something that promotes clean renewable projects. And they're probably the two -- they're two of the largest, for certain, QFs in the system.

 

In terms of cost savings and competition, oftentimes I think PURPA has in some ways undercut competition. And I think that NARUC did a paper that Travis was heavily involved in. He can probably speak to it a bit more, but I think it lays out this case very well. And what it deals with is the ability to use the statute and use the rules that implementing the statute in ways that undercut competitive pricing.

 

The record suggests, and Commissioner McNamee in his concurrence on the order adopting the rulemaking pointed out, that the records suggest that somewhere between 2.2 billion to 3.9 billion dollars in electricity cost were probably overpaid by customers in relation to what they would've had to pay in a more competitive environment, simply because of the mandate and PURPA being used as this cudgel, basically.

 

In response to that, state commissions were really pulling their hair out trying to figure out how to get some relief for some consumers because FERC's rule didn't have a lot of flexibility built into them, unfortunately, I think, we'll have much more flexibility now moving forward. The one tool that state commissions are looking at was shortening contracts. That's not good for the QF developer, but it did offer some potential help for customers. And that was one of the things that states were trying to do to alleviate it.

 

Again, as Commissioner McNamee pointed out in his concurrence, I think you can make a reasonable argument that actually the mandates of the statute are better for developers if they can receive some longer term contracts than in relation to what was happening, which was really just an attempt by state commissions to protect their own consumers.

 

So with that, I'll wrap up my introductory comments. As I said, I think in the broad strokes, the Commission generally got it right. We'll talk about it in Q&A a little bit more about what they got more right, then maybe some missed opportunities in other areas. But I think it can be safely said that, at least in my opinion, the Commission did a good job of refreshing the rules in a way that continues to support the statute but gives consumers and state commissions more flexibility to implement the statute in ways that make sense given today's electricity marketplace.

 

Travis Kavulla:  Thank you, Tony.

 

Adam Griffin:  Thank you, Tony. Go ahead, Travis. I was getting ready to --

 

Travis Kavulla:  Oh, thanks. All right. Thank you, Adam. Thank you, Tony. Thanks to The Federalist Society as well and thanks for tackling the topic on energy regulations that you don't often hear about but which, as Tony says, is really important to anywhere between about a dozen to 20 states that are not part of one of these organized markets.

 

      And I thought I'd back up and talk a little bit about the core legal mandates of purpose, so those red lines in the statute that FERC can't cross, and then connect it back to what we see in terms of FERC's rulemaking and why the situation that Tony describes has been precipitated by a statute that appears to seem competitively neutral, not really geared to producing excess costs, but which, nevertheless, I think has. The evidence pretty clearly demonstrates.

 

      So two core legal mandates in PURPA, first, that state regulators can't discriminate in the rates they pay to qualifying facilities as -- QFs, as they're known under PURPA, and the rates that the state regulators authorize for utilities themselves through the energy and capacity their powerplants provide the system.

 

      And second, that rates paid to QFs need to be set on so-called avoided costs, what utilities would otherwise pay if the QFs were not online. Again, good principles and to add to that, those are core mandates out of the 1978 statutory enactment. And then the situation, the bifurcation that Tony described came about as a result of the energy policy act in 2005, where Congress surgically said that there could be relief from the mandatory purchase obligation under PURPA if the QFs weren't' trapped behind the gates of utility monopolies.

 

      So where they do participate in these regionally organized wholesale markets, in RTOS in other words -- and if anyone is unclear about what's an RTO and what's not, just go onto your favorite search engine and type RTO, and you'll see a colorful map displaying where they exist and where they don't. But in the places on such a map where color exists, PURPA really is a non-issue except for certain cogeneration facilities typically. But elsewhere, as Tony describes, it has been a big issue.

 

      So going to how state regulators have implemented PURPA in those states where it is a big issue, I think it's important to really consider that since discrimination is the key legal mandate, that is avoiding it, that we need to consider how utilities themselves make money on energy and capacity, to consider how, then, in practice QFs end up being paid for their production.

 

      And the utilities capital investment is what utility regulators call rate based. And this figure is based on the actual cost, typically to the utility, to buy or build a power plant. But it's justified to regulators on assertions that the utility generator's capacity and energy will be in the money over the long term compared to other possible investments, including buying energy from third party sources or from the open market.

 

      Once those investments are approved by regulators, the risk of that guess work is largely shifted away from utilities in the regions that we're talking about and onto consumers. If the utility makes an investment in year zero and by year ten, it turns out to be a total dud, the financial consequences of that, sad to say, are not shouldered by the utility and its shareholders typically. They're instead shouldered by customers.

 

      Add to that the fact that utilities tend to be paid on return to equity in most U.S. jurisdictions that exceeds their actual cost of capital. In any case, it's well above the average of utility regulation in OECD countries. And incentive exists in utility regulation to spend more and make more, to always be presenting forecasts of energy and capacity that make higher priced investments or building your own power plant look favored.

 

      So PURPA, as imagined by its proponents at the time of adoption, was supposed to introduce competition to constrain this particular perverse incentive that I'm talking about, in addition to diversifying sources and supply so that we weren't just relying especially on foreign oil but even on just domestic sources of supply that were uniform like coal.

 

      Unfortunately, it really has not turned out to work that way. And the fundamental problem here is that PURPA hasn't been implemented to rely on head to head competition with utility owned generators, which might drive prices down and which is how power options work in the RTO competitive regions that we've been talking about.

 

      Instead, QFs tend to use utilities' own avoided cost forecasts, making certain adjustments to them themselves with some regulatory intervention. And as I've just mentioned, those forecasts tend to be used to justify utilities' own investments. So in other words, they tend to aim pretty high.

 

      So to date, to put a fine point on this, PURPA implementation, even though it's often couched in the rubric of competitive markets, is really just a weak Xerox effect of the worst parts of utility regulation. It's not competition in the sense of actually getting power plants to bid against one another. Its, instead, competition of the sense that says hey, we give you utilities this sweet deal where we allow you to pad rate-base, so we're going to turn it around and basically do the same thing for these third parties, who for a variety of reasons that I need not get into are sometimes in an even better position to game the system using cost forecasting techniques.

 

      So, again, it hasn't resulted in competition. It's just resulted in, I guess you can say, a type of competition that enfolds before regulatory agencies to procure administrative favors. And my goodness, when I was a state utility commissioner, that type of litigation practice abounded. I've said it publicly before that somewhere between a quarter to a half of my time, depending on the year as a regulator, was sitting playing referee in disputes between QF projects under PURPA and the utility and its consumers that were in under obligation to buy them at avoided cost.

 

      And each party would trot out their expert witnesses, providing the quote on quote "right price forecast for energy and capacity." And the person who ended up having to decide which forecast was right was me and my colleagues, government officials, regulatory commissioners, who frankly, I mean, put aside our relative expertise or lack thereof, it was also just the fact that it was no skin of their teeth, our teeth, or resultingly the QF's teeth, or even the utilities' teeth, what price we authorized. Because once we had spoken and locked in a rate, all of the risk of forecast error, which was inevitable, transferred to consumers.

 

      And a funny thing happens when you're asking regulators to name the right price. If the regulator names a price that is too low for the QF to actually get built, well, it won't get built. And even though the regulator thinks they've done a good job at calling out the proper economic forecasting of the power sector, those benefits or that accuracy, one might say, is not going to redound to the benefit of consumers because the project simply won't come under contract and ultimately, commercially operational.

 

      Whereas, if the utility makes an error in the other side, is too generous with how they forecast prices for QFs, well, then the gold rush begins. And that's really what we've seen in practice in a lot of QF development across the country, and it's what drives the kind of excess costs that Tony has been talking about and which I agree with.

 

      So in other words, despite the notion that QFs are paid only in avoided cost or that QFs rates are not discriminatory relative to utility rates, the practical effect of what I'm discussing always tends to err, it seems, on getting projects on the high side.

 

      So just a couple points about the good and not so good of the FERC rule before we open it up to discussion. First, I think the most positive part of what FERC has done in this rulemaking, which is really the first major rulemaking on PURPA since rules were implemented in 1982, is that it said that utilities can set avoided cost using competitive solicitations. In other words, you can comply with PURPA not through looking into the glass ball as I was just describing, but instead putting generators in competition with one another.

 

      Now, there's a lot of details in that. FERC adopted the so-called Allegheny standards to try to eliminate self-dealing opportunities or gaming on the part of utilities. I, myself, take a pretty strong position on this. I think personally, and my firm as well believes this, that probably we should have monopolies be no larger than they need to be in order to get their infrastructure done.

 

      I think it's hard to have a genuinely competitive generation market if you allow these monopolies to be entangled in what should be a competitive business. But putting that aside, it's important that FERC at least said competitive solicitations can be used to comply with PURPA and put some guide boards around it.

 

      Second, I'll call out as this not so good element, that the Commission allowed states to set energy avoided cost on a variable basis rather than a fixed basis. And you may be saying well, I thought you just said fixed based energy pricing is wrong because the guesses are always wrong. I agree, and I think that would be a good thing were the situation to apply to utilities themselves.

 

      But FERC stopped short of requiring that to be a precondition of this form of PURPA implementation. FERC, instead, seems to be assuming that regulated utilities are subject to market price volatility in what they collect in revenue for energy output of their plants. And the reality is that they just aren't, at least not uniformly.

 

      If I build or buy a nuclear power plant, like Southern Company's doing, or hydro-electric facilities, like the company I regulated in Montana did, or Windom Solar as a utility, I'm essentially locking in the price of energy from those utilities with the same kind of administrative guesswork we rightly criticized when it comes to PURPA implementation. And we've likewise seen long term coal contracts and gas supply transactions. So even for facilities where fuel is the driver of energy cost, we've seen the same thing.

 

      Now, these fields might be good or bad or indifferent, but what they do is ensure that customer pricing doesn't end up bearing a direct relationship to changes in the market place, at least in situations that still have a monopoly and can pass along those costs to the captive set of consumers.

 

      So with that said, I generally view the FERC order as a well-reasoned piece of work. It runs about 500 pages long, not on the register but on the PDF document. And I think pretty much everything FERC did in the order would be worthy of praise if it applied evenly to everyone. And even where they didn't, I think they've opened up some really meaningful opportunities for both customer savings as well as competitive neutrality in some important places.

 

      Again, thank you for the opportunity.

 

Adam Griffin:  Thank you, Travis, and thank you, Tony. I'm going to give each of you a couple of minutes if you have any points that you want to comment on the other's presentation or any questions to the other one. So, Tony, if you'd like to start on that.

 

Anthony T. Clark:  Sure. Just a couple of reactions, and this one probably isn't going to surprise Travis a whole lot because we've discussed these issues in the past. But I'm not -- this is something that was, I think, discussed a little bit actually at the Commission meeting upon adoption. If I remember, Commissioner Danly maybe spoke a little bit to this, and Commissioner Glick had commented on this.

 

      But it's this question that Travis had raised at the end about standards applying evenly to everyone. And I think this is really -- it's helped highlight in my mind some of the problems with PURPA which is, in my mind, there is a significant difference between most PURPA projects and projects that are built within an integrated resource plan for utility.

 

      And they should be treated differently because they're not similarly situated. And this -- when I say within an integrated resource plan, these could be projects either self-built by the utility and approved by the Commission and built into rate base or projects that were built by a third party merchant developer and made it through a competitive solicitation process in an integrated resource plan.

 

      When a project is developed as part of a regulated asset or within a plan, it's serving some sort of specific need to provide 24/7 energy to consumers, hopefully on a least cost basis. And there are ways to interject competition into that process through things like RFPs.

 

      PURPA projects are very different, however. Because the statute is written excluding need or location or all sorts of things that engineers who build these networks take a look at, it's a legal entitlement. And so whether the project is really in an optimal place on the transmission grid, whether it provides energy when the energy is most needed as opposed to when the wholesale markets are flooded with energy, all those things go out the window.

 

      So in my mind, they are very much different projects. And for this reason, it's appropriate to treat them differently than those projects that are built as some sort of planned process within those states that have chosen to continue to have vertically integrated utilities.

 

      The second reaction that I have, which I think is illustrative of some of the problems that can come out of PURPA as Travis talked about them, was this issue of once the PURPA Put is there and the cost simply flow through to consumers is correct. At that point, consumers bear all of the cost of those. They just kind of flow through and may not directly impact the bottom line of the regulated utility.

 

But there is an impact on the regulated utility, and I would argue consumers, beyond just those costs of the project that may or may not be providing particularly viable energy at the time that it provides it, which is all of those actions, and when you look at some of these systems across the western or southeast part of the U.S., they incrementally add all of these costs onto consumers. That creates a lot of rate pressure on consumers.

 

And what it means is for the still regulated portions of the traditionally regulated portion of the utility assets, maybe investments in grid modernization, distribution wires investments that position the grid that's beneficial for the future, it gets tougher for the utility, the regulated utility, to make those investments because they're in a cost environment where the regulator is concerned, rightfully so, with the cost that consumers are paying.

 

And all that upward rate pressure makes it more difficult to make those investments that buffer that rate pressure that might be widely accepted by lots of stakeholders as being necessary for either liability or market efficiency. So it does have a spillover effect into other aspects of the regulated utilities and I think ultimately to consumers themselves.

 

Travis Kavulla:  I'll just take the brief opportunity to respond because I think Tony and I do amicably disagree on a couple of points in what he just said. Although, I think we agree on a lot of this stuff. I think where we disagree is how we view and whether we view the integrated resource plan that Tony talks about as being fundamentally different than the type of administrative price forecasting that happens for QFs.

 

      And I guess I don't see the same gradation of difference that Tony does. In an integrated resource plan, yes, there's one big Borg-like model that's considering system needs and running it by a bunch of anticipated, not actual because you don't know it until it actually happens, anticipated cost data for the resources that are in the mix.

 

But fundamentally, it still relies on the kind of regulatory command and active mandate by which those costs are ordered into rates and where the risk of forecasting wrong, albeit perhaps through a more finely tuned central model, where that risk is still transferred onto the consumers if the bet turns out to be misplaced.

 

      And we have seen integrated resource plans that appear to buy us certain technologies that might be more to the greater financial reward of regulated utilities, for some of the reasons I talked about in my introductory comments, and so there's reasons to be skeptical of that.

 

      Now, that is different, I agree with Tony, it is different than the kind of ad hoc, call-and-response litany of QF pricing litigation where you're trying to use cost elements broken out of that integrated resource plan model to interact with open market prices to come up with a price forecast that's then delivered to an individual qualifying facility for the purpose of contracting. But at its core, both of those have in common the same big risk shift to consumers of guessing wrong.

 

      And that's really, frankly, what's missing in these parts of the country we're talking about, is the fact that generators need to wear more of the responsibility of having bet wrong. And that's where business models that require -- if I in my company go out on the basis of what I estimate market prices are going to be over the next 5-10-20 years, and I build a power generator in response to the market prices I anticipate, and I'm wrong, and my plant ends up being out of the money, well, that's on me and my shareholders.

 

      And we've seen in the competitive markets a lot of power generators get wiped out into bankruptcy and then solvency by making those wrong bets. And those costs don't end up redounding to consumers. They end up falling on whoever the equity and debtholders are.

 

      There's a flipside, which is obviously you keep upside benefits as well if you bet wrong and then it turns out to be even better. Then that, nevertheless, I think that type of regulatory model better assigns the risk we're talking about of trying to bet on prices to the right people rather than expecting regulation to do it for you which proves, I think, again and again, it'd be the wrong way of going about this.

 

Adam Griffin:  Thanks, Tony. Thanks, Travis. Greg, do you want to open up the floor for questions? Do we have any in the queue?

 

Greg Walsh:  Yeah, let's do that now. We'll now go to the first question.

 

Caller 1:  Yes, good afternoon. Fascinating topic. I'm just curious if you gentlemen could respond to -- so the argument that PURPA has outlived its usefulness, it's kind of a solution in search of a problem now. I mean, a statute that was originally enacted to address the oil embargo of 1970s and the ersatz energy crisis in an era in which we now are variously energy independent as a nation in which many, if not all, markets offer your choice of power generator. If you want to pay more for your power because it's green or something like that, that's available.

 

It seems like almost an artificial subsidy that's being created through this. And I realize there would need to be political will to change it, which may or may not be there, to actually repeal it. But it just seems like PURPA, maybe FERC overall, is a dinosaur.

 

Anthony T. Clark:  Yeah, this is Tony. I think the point is very well taken, and this really gets to a public policy question that is ultimately up to Congress. But I think you're exactly right. You have to really think back to the genesis of PURPA, which may be -- I may have made this comment in a -- I think I made it in a statement or speech somewhere when I was on the Commission or I made it in a separate statement, I can't remember. But we're now -- PURPA is closer in time to Pearl Harbor than we are to PURPA.

 

      It was a statute that came out of the '70s energy crisis in the era of oil embargo. And it was a time in which the country was dealing with the shortages and extreme price volatility in oil and gas prices. And so it was an attempt to one, try to get away from those problems that were immediately occurring in the '70s energy crisis but also as an attempt to interject some bits of competition into a regulatory regime which was very siloed at that point.

 

      And a lot has changed. You mentioned some of them in the question, but I -- including the emergence of markets in parts of the country. But even in parts of the country that are still both vertically integrated and outside of the organized markets, with things like Order 888 which guarantees open access to the transmission grid, which is something that wasn't even contemplated at the time that PURPA was put in there.

 

      So I think in many ways, the statute itself is relatively dated, and it would make sense for the statute to be either significantly reformed or repealed. The viability of getting that done is very difficult in Congress, of course, assuming that filibuster remains after January. But so I think the question's a good one. FERC, within its authority, I think did a good job of trying to modernize it, which it clearly does have at least that amount of authority. But if bigger changes were to be made, likely those are going to come through Congress.

 

And it does bear mentioning and acknowledging that in EPAct '05, PURPA could've been repealed at that time. Congress chose not to and in fact added some language in relation to what the obligation for utilities were going to be that were operating within the organized markets. So it tipped its hat to some of the things that had changed between '78 and '05. But nonetheless, I think the core of the question is a very good point.

 

Travis Kavulla:  Yes. I generally agree. Two quick points on this. First, assuming congressional inaction, which is always a safe bet, it then leaves the question to regulators. And are you going to be a regulator who looks at the statute and says god, this just does not make any sense anymore, and we're just going to try to minimize its effects because it is so senseless? Or do you look at it and say oh, well, there's enough wiggle room in the statutory language to allow this statute to be repurposed as a more meaningful catalyst for competition in the places that don't yet have a fuller measure of competition like some of the eastern electricity markets do?

 

      And so I think there's a legitimate debate to be had there. And I think you can argue it in some sense both ways on statutory intent. It is one of these statutes, it's not as bareboned as the Federal Power Act itself, which famously uses the language that all rates shall be just and reasonable and any rate which is in any respect unjust or unreasonable is declared unlawful, which is sort of a high water mark of delegation to FERC to figure out what that means. But PURPA comes pretty close to that.

 

      Discrimination and avoided cost, as Tony said in the beginning, there's a lot of ways to fiddle around with those concepts within the four corners of the law. But this is a question that keeps presenting itself to energy regulators and environmental regulators as they try to regulate carbon dioxide through the Clean Air Act, a statute which clearly was not intended for it but which Co2 can awkwardly be fit into.

 

      To the questioner's other point, it is one fascinating datapoint that I see is in some of the states where PURPA activity has been highest, you see strange fissures erupting between big scale independent developers of renewable generation and the subset of QF developers.

 

And Colorado is a good example of that where the utility went through a big competitive solicitation to try to get more wind and other renewables on its system. They got some real rock bottom prices out of it. Some of the projects ended up working, some of them did not. Any case, the prices that came in were pretty low, and then the set of QF developers, again, also working on the same fuel source, wind, raised their hand and said no, no, no, no, we're entitled to an earlier vintage of avoided cost forecast by the regulator that forecasts a much higher price.

 

      So even though you tested the market in a much more direct way by putting out a competitive solicitation, you still had these people arguing for this PURPA entitlement. And that is, again, we can talk about how to improve competitive solicitations and make them more genuine and legitimate all day long. We should, but it's crazy to have PURPA be this crutch that relies so much on administrative price forecasting, which, again, is the central tendency of utility regulation itself and which is wrong.

 

Anthony T. Clark:  Travis brought up the Colorado situation, and I think Idaho was -- or not Idaho, Pacific Corp, I think, and I can't remember which state it was in, was another one that the NARUC whitepaper discussed and was kind of typical of this, what I would call, gaming of the system where you may have project developers that have relatively large projects that go through some sort of competitive RFP process are not selected for some, perhaps, very legitimate reasons.

 

Some have to do with cost, some energy versus capacity, some locationally, or there may be better options for consumers. But the ones not selected can disaggregate their projects into a large number of 79.5 megawatt projects, which look an awful lot like being maybe 250 or 500 or 1000-megawatt project that they had originally proposed and then cram it in as they -- it's a PURPA enforceable obligation. That's one of the examples of gaming that can go on.

 

      And one part of the rule that FERC did address that maybe curbed some of these abuses, although I have some concerns, they could have put a little bit more teeth into it perhaps, is the disaggregation rule where at least there is now an ability for projects that are disaggregated beyond a mile to challenge that and to be able to prove that no, in fact, it's still one project just disaggregated in such a way as to game the system and make them look like a number of QFs.

 

Greg Walsh:  Let's go to our next caller.

 

Caller 2:  Well, thanks for taking my question, which is how do these changes or any future PURPA change impact executed QF contracts? So meaning, can a contracted project be immediately impacted or only after its PPA ends and re-contracting comes up?

 

Anthony T. Clark:  The way FERC addressed that is they grandfathered in existing legally enforceable obligations, and then on a going forward basis, I think, someone can correct me if I'm wrong, but based on when the rule is formally adopted, publication at the federal register, then it will apply to -- or state commissions will have the flexibility to implement pricing flexibility along the lines of what's contemplated in the new rule.

 

      And then presumably, as older projects roll off of their existing contracts, they would be -- well, either they won't reup or if they do, it would be under the new rulemaking regime.

 

Travis Kavulla:  That's my understanding too.

 

Greg Walsh:  Let's go to our next caller.

 

Caller 3:  Yeah, thanks. Sorry for my ignorance of the statute, but I'm just curious. So the title of the program was, "Retooling Energy Regulations: Who Decides?" And I wonder if the Commission thought that the statute would have the authority to basically push it entirely to state public utility commissions.

 

I, in the spirit of federalism and trying to get these costs closer to political accountability, if we can, you can't achieve a fully market-based solution, seems like public utility commissions are pretty responsive to consumer pressures, maybe less removed than layers of bureaucracy through FERC. So I would just be interested in your response to that prospect.

 

Anthony T. Clark:  There was a, I thought, intriguing proposal, but I'll let Travis explain in more detail since he helped develop it. But the NARUC yardstick proposal which would have done something along those lines where state commissions would've had, given certain assumptions, for example, a transparent RFP process, maybe administered by a third party administrator, so that you have aspects of competitive pressures built into that if a project came through that sort of integrated resource planning process, then it could alleviate some of these PURPA obligations in the same way that utilities operating within fully organized RTOs have their obligations relieved above a certain point. But I'll let Travis explain a little but more about that proposal. It wasn't entirely adopted by the Commission.

 

Travis Kavulla:  Yes. Thanks for the shoutout, Tony. So what NARUC had proposed, and I co-opted this whitepaper, was to, I guess I would say, fully and properly implement the amendments to PURPA of EP Act '05. And what that law did is specify three categories of -- realizing that the electricity markets had evolved, it specified three categories of market change that, if they had occurred, could qualify for a full exemption from the mandatory purchase obligation under PURPA.

 

      And a couple of those categories described what we now call RTOs, but then there was one of these peculiar subsection Cs that said other markets of comparable competitive quality. And no one -- and, really, it falls on FERC to explain, I think, what that means since Congress had some reason for writing it. FERC has never really explained what you could do short of joining an RTO to trigger that provision of the statute.

 

      And so NARUC proposed that it was time to create a yardstick to basically signal to western states and those southeastern states that had not joined an RTO, and may never join an RTO, what they could do in terms of bulk power procurements of energy and capacity to satisfy the comparable competitive quality requirement of EP Act '05.

 

      And FERC basically took a pass. Instead of saying these -- they did spell out some principles for competitive solicitations as I said before as a way of complying with states coming up with the quote on quote "right avoided cost." But that's an act that keeps their fingers in the pie of PURPA implementation.

 

And I think a more robust way of fulfilling Congress's purpose would be for FERC to take a hard look at some of the issues, come up with a yardstick, allow states and utilities and QFs and other independent power producers to think how they could work toward meeting that yardstick in their own way.

 

And then FERC, at some point, simply calling the game, declaring those utilities exempt from PURPA, and sending people home to the states to go about their business. But that isn't what FERC did. It was a bit disappointing. They did not close the door fully. They basically said that any utility could come to them with a petition making a showing that they met the ambiguous standards under that subsection and try to obtain an exemption.

 

And maybe some of them will because even after this reform is implemented, PURPA implementation is going to take up a huge amount of time, and there's going to be a huge amount of back and forth between states and the FERC. So to be seen whether utilities try to make that pitch, but I agree with the questioner. There were opportunities where you could've drawn a clearer line and where PURPA issues wouldn't constantly have to recirculate back to Washington to receive a determination.

 

Greg Walsh:  Well, Adam, it doesn't look like we have anymore callers in the queue. Do you have a final angle you'd like to tackle or any concluding thoughts from either of our experts?

 

Adam Griffin:  Thanks, Greg. I did have one question. There's a previous Teleforum where we had talked about the new NIPA reforms. And someone claimed that the great weakness of this rulemaking is that the agency did not do a NIPA analysis before it issued the PURPA rulemaking. Indeed, Commissioner Glick's dissent on the rulemaking expressly called out the lack of a NIPA analysis. Do you agree or disagree that the agency should've done a NIPA analysis? What are the pros and cons of not doing a NIPA analysis? And does it matter to the ultimate benefits or detriments of the rule?

 

Anthony T. Clark:  So --

 

Travis Kavulla:  Yeah -- go ahead, Tony.

 

Anthony T. Clark:  Okay, sure. So my gut reaction, quite candidly, when I heard the NIPA argument is I probably rolled my eyes just a little bit. It seems like a bit of a longshot to me being that this is really just an update of an existing rule.

 

      But beyond that, could it have some legs? I don't know. To me, the real [inaudible 54:17] that sort of line of attack is that there have been other issues where someone has raised a procedural -- or a party has raised a procedural type objection like that. And if you get in a particular venue where a particular judge really wants to decide in a [inaudible 54:40], they’ll sometimes take up arguments that I think are a little off the wall.

 

      And candidly, the environmental movement's been pretty successful in -- at least in certain cases in recent years of raising some arguments and objections and being able to draw out and block projects, or at least defeat through delay projects, by raising some kind of tangential argument sometimes that maybe in previous years wouldn't have been taken as seriously but a particular venue gets selected and it goes up on that particular issue.

 

      So, again, my gut reaction is I don't sense that this needed a NIPA review. And FERC did address that issue in the order, but you just never know when some of these things get litigated given the state of the courts there.

 

Travis Kavulla:  Yeah. Boy, if judicial review of this regulation turns on NIPA, we're all the worse for it, I guess would be my instant take. You just heard an hour of Tony and I politely agreeing and disagreeing and amicably talking about the merits of this policy decision. And it really would be a shame if we have a system that seemingly decides all questions on whether or not someone has produced a voluminous report that few if any people read or, candidly, take very seriously, which is I think what a NIPA report on PURPA would really in effect amount to.

 

      The people arguing this do have a good point. They point out that FERC, when it first implemented the 1980s rules did a NIPA analysis. They cite to an administrative regulation at FERC that seems to suggest a NIPA analysis is required. FERC probably would've been on firmer ground had it done a NIPA analysis. But the reality is, taken at FERC's word, that it's merely making changes to ratemaking in a way that shouldn't affect overall adoption of renewables onto the system.

 

      And, again, it's a false assumption that QFs instantly mean renewables. But let's just take FERC at their word that then really NIPA and its major impact on the human environment language probably should not be triggered. But it definitely is something that people have seized on as a weak point. It's clear just reading the Commission's order and Commissioner Glick's dissent back and forth that it was a topic they thought they might be stumbling over. And so it'll be interesting to see the litigation angles on that.

 

Adam Griffin:  Well, Tony and Travis, thank you both so much for lending us your time and expertise to discuss this new PURPA rule and the important implications and impacts it may have. I'll give the last word to each of you. Do you have any closing remarks, any brief closing remarks?

 

Anthony T. Clark:  No. Just thank you for the opportunity to be here and for FedSoc for hosting this. It's been a good discussion. And in closing, I just say that I congratulate FERC for taking up this project and making a decision on it. Tt took a while to get there, but I think where they got was generally a pretty good place.

 

And coming out of it the big winners, I think if you were tallying winners in a rulemaking like this, is consumers who will have some ability -- they have a better level of protection by their state commissions being given the opportunity to flexibly address some of these issues that have arisen out of PURPA given the state of where it's evolved over the last 40-something years.

 

Travis Kavulla:  And I'll just conclude by saying that Tony and Adam and Federalist Society, I appreciate the opportunity and I hope everyone has a pleasant rest of the week.

 

Adam Griffin:  Thank you so much.

 

Greg Walsh:  On behalf of The Federalist Society, I want to thank our speakers for the benefit of their valuable time and expertise today. We welcome listener feedback by email at info@fedsoc.org. Thank you all for joining us. We are adjourned.

 

[Music]

 

Dean Reuter:  Thank you for listening to this episode of Teleforum, a podcast of The Federalist Society’s practice groups. For more information about The Federalist Society, the practice groups, and to become a Federalist Society member, please visit our website at fedsoc.org.