The Energy Policy Act and Cogeneration – What the QF?

Michael Giberson

FERC has issued a new proposed rule that would revise regulations governing “Qualifying Facilities” (QF). QFs are small renewable energy generators or cogeneration facilities that, under the Public Utility Regulatory Policies Act of 1978, gained the right to sell power to public utilities at the utilities’ “avoided cost.” This right to sell power, and other benefits gained by qualifying as a QF, are sufficient encouragement to raise concerns about so-called sham cogeneration units. The new regulations appear to get FERC more closely involved in determining whether a cogen QF really is using the thermal output in a “productive manner.”

Traditionally the federal government has deferred to the states on many PURPA implementation issues. I wonder whether we need the Feds to be more involved here. I guess my real question is whether, overall, the Energy Policy Act will be a good thing for cogeneration or not. I couldn’t tell after reading the FERC press release concerning the new proposed rule, but thought that maybe one of KP’s readers could provide me with an informed opinion.

Here is a piece of the FERC press release:

New criteria proposed for cogeneration facilities, QF ownership restrictions would be eliminated

Acting under an Energy Policy Act of 2005 mandate, the Federal Energy Regulatory Commission today proposed to revise its regulations for small power production and cogeneration facilities. The Commission proposes to eliminate ownership restrictions and to ensure that thermal output of facilities is utilized productively and beneficially.

The proposed rule would amend Commission regulations to effectively end its “presumptively useful” standard in determining whether a cogeneration facility’s thermal output is useful. […]

In the future, the proposal states, the Commission “will scrutinize the use a cogeneration facility makes of its thermal output to assure that the use is not a ‘sham’ and the thermal output is used in a ‘productive and beneficial manner’.” The Commission will consider the uses to which the product produced by the thermal output is put, including factors such as whether the product is needed and whether there is a market. The Commission said that it will more closely scrutinize facilities that only satisfy “minimal” operating standards. […]

Section 1253 of the Energy Policy Act also amends PURPA by terminating the mandatory purchase and sale obligations in certain circumstances. The Commission will address this provision in a separate rulemaking proposal in the near future.

More background on PURPA is available from the Energy Information Administration.


24 thoughts on “The Energy Policy Act and Cogeneration – What the QF?

  1. It’s difficult to imagine how anything passed by this congress would be good for cogeneration, but in an odd way this might be.

    Utilities have always opposed PURPA, especially their must-purchase obligation. Even worse, the ownership restrictions meant that the utilities were obligated to purchase from someone other than themselves. I don’t think that efficiency was an issue for the utilities except that low efficiency standards meant that more generators could qualify for the obligatory purchase under avoided-cost pricing. In some cases the states set avoided-cost pricing that was way too high, even higher than entry cost for a conventional generator. And in some cases it may have been that the avoided costs really were just that high. The efficiency restrictions were a hoop that prospective cogenerators had to jump through to qualify for the avoided-cost pricing and the must-purchase obligation.

    Raising the efficiency standards does further restrict the kinds of projects that qualify for must-purchase, but at this point in the game that seems OK. It doesn’t hurt cogenerators that really fit with an industrial process and have a very low heat-rate-chargeable-to-power. I’ve seen projects with a power-chargeable heat rate of 5000. As a nation we should encourage incremental investments that can convert energy to electricity at such rates, but my guess is that the increased restrictions will not eliminate such true opportunities. It might eliminate some projects that were just dressed up to qualify for must-purchase, but that were really no more efficient than a conventional plant. I do believe in competitive generation, but I stop short of requiring utilities to purchase from all competitors at an administratively determined price. There has to be a good reason for it, and very high efficiency was a legitimate reason.

    The easing of ownership restrictions might actually cause more cogeneration to be developed. Some good inside-the-fence generation opportunities were “bought down” by the utilities through “cogeneration deferral” rates. I doubt anybody really called them that, but it means that there are possibly some undeveloped opportunities remaining, as well as future opportunities of that type. Now that the utilities can build and own the generation themselves, they will be more likely to develop these opportunities rather than suppress them. All that said, I’m in the dark about whether there really are many more really good opportunities out there waiting to be developed.

    In sum, these changes require cogenerators to be the real thing, and they ease the restrictions on utilities to invest in them. We’ll have to wait and see, however, how FERC amends the must-purchase obligation. [In a system with an available spot market there should be no such thing as a must-purchase obligation on anybody. But within vertically integrated utilities without an independent spot market, the must-purchase obligation makes sense.]

  2. I have appraised cogeneration operations where, due to the bankruptcy of the thermal host, the cogenerator constructed a water distillation plant to serve as a replacement thermal host even though there was actually no market for the distilled water. The water distillation plant allowed the cogenerator to maintain QF status and retain an over market power purchase agreement with the utility.

  3. Looks like this new rule effectively ends some QFs as we know them. It requires that the total output of a cogen unit (including the “chemical” output, whatever that is) to be “fundamentally” (whatever that means) intended for use by the QF host, and not for sale to the utility. Not too many QF hosts out there that can consume a sizable portion of a 1000 MW combined cycle plant. The days of those large cogen plants may be over.

    Could the rules be any more unclear? Who knows what they mean. And if, as FERC proposes, all of the standards for use of the output and efficiency will be decided on a case-by-case basis, then looks like the little guy trying to get his small cogen unit certified had better either higher a high-priced lawyer or take the time to familiarize himself with a ream of case law. Good luck Ma and Pa!

  4. Maybe Ma and Pa, Inc. could make it as an aggregator, selling the output of 10,000 home-sized cogenerators.  They’d probably have to do the paperwork only once.

  5. I don’t read it that way, Charlie, if we’re referring to that FERC press release quoted above. It didn’t say that the “total output” has to be consumed by the host; it said that the *thermal* output must be used productively. That means that the steam offtake must be used in a real industrial process, not in something valueless such as the distilled water example above.

    Chemical, paper, and refining processes, for example, can often incorporate a cogen plant that can produce surplus electricity as a byproduct. The incremental investment to do so, and the incremental fuel cost to do so, combine to provide this surplus electric energy very efficiently and inexpensively. Since utilities would generally oppose such installations on principle, and since generating power for resale would cause these companies to be state regulated as utilities, PURPA was passed to provide exemption from state regulation and to obligate the utilities to buy from them at avoided cost. Anything that wasn’t worth doing for payment at avoided cost wasn’t worth doing. Anything that cost less than utility avoided cost was worth doing, so PURPA was intended to encourage these super-efficient investments by people who had a steam need and were burning fuel (gas or coal) already. And it was timely, because environmental regulations were forcing many of these industries to replace their old boilers. If you have a large steam load and a need to replace your boiler, then cogeneration can be a very inexpensive add-on.

    I think the increased scrutiny given to the thermal output will restrict QF status to those kinds of highly efficient installations, as opposed to those that have a “sham” steam host. That means that if you build an IPP in an area that does not have wholesale competition, then you don’t have much chance of forcing the local utility to buy from you at PURPA rates by dreaming up some sort of valueless way of using thermal waste heat. This isn’t a problem for real cogen. However, it is a legitimate question whether this change is better public policy or worse.

    My problem with PURPA wasn’t with the idea, it was with the implementation. Avoided-cost pricing is problematic, and there were states that worked hard to encourage cogen and renewables by setting avoided-cost prices relatively high. That was just stupid, to put it bluntly, and those states’ customers have suffered very high prices as a result. If you set a high avoided-cost price, then regular IPPs could make money at that (especially with what was happening in generation technology and fuel at the time). All they need is some excuse to call themselves a QF. But that’s not efficient unless the avoided-cost prices are really accurate and even-handed. The most famous problems were NY and CA, which both bought too much “cogen” at prices designed to avoid new nuclear plants. (In a famous FERC decision, the CA avoided-cost prices were determined to be higher than “true” avoided cost, and were ruled invalid. This broke the regulator-dominated planning process, and was a large factor pushing that state toward restructuring.) As long as these prices are set administratively and utilities are forced to buy at these prices, I’m all for increased scrutiny over the kinds of projects that qualify for the must-purchase option. I’m not so sure it’s a big deal any more, though. I think this item has been “on the list” for some of the remaining large integrated utilities for quite some time. This energy bill was an opportunity for them to get almost everything that had ever wanted. They had long wanted PUHCA and PURPA repeal. This is just a PURPA tightening.

  6. I don’t read it that way, Charlie, if we’re referring to that FERC press release quoted above. It didn’t say that the “total output” has to be consumed by the host; it said that the *thermal* output must be used productively. That means that the steam offtake must be used in a real industrial process, not in something valueless such as the distilled water example above.

    Chemical, paper, and refining processes, for example, can often incorporate a cogen plant that can produce surplus electricity as a byproduct. The incremental investment to do so, and the incremental fuel cost to do so, combine to provide this surplus electric energy very efficiently and inexpensively. Since utilities would generally oppose such installations on principle, and since generating power for resale would cause these companies to be state regulated as utilities, PURPA was passed to provide exemption from state regulation and to obligate the utilities to buy from them at avoided cost. Anything that wasn’t worth doing for payment at avoided cost wasn’t worth doing. Anything that cost less than utility avoided cost was worth doing, so PURPA was intended to encourage these super-efficient investments by people who had a steam need and were burning fuel (gas or coal) already. And it was timely, because environmental regulations were forcing many of these industries to replace their old boilers. If you have a large steam load and a need to replace your boiler, then cogeneration can be a very inexpensive add-on.

    I think the increased scrutiny given to the thermal output will restrict QF status to those kinds of highly efficient installations, as opposed to those that have a “sham” steam host. That means that if you build an IPP in an area that does not have wholesale competition, then you don’t have much chance of forcing the local utility to buy from you at PURPA rates by dreaming up some sort of valueless way of using thermal waste heat. This isn’t a problem for real cogen. However, it is a legitimate question whether this change is better public policy or worse.

    My problem with PURPA wasn’t with the idea, it was with the implementation. Avoided-cost pricing is problematic, and there were states that worked hard to encourage cogen and renewables by setting avoided-cost prices relatively high. That was just stupid, to put it bluntly, and those states’ customers have suffered very high prices as a result. If you set a high avoided-cost price, then regular IPPs could make money at that (especially with what was happening in generation technology and fuel at the time). All they need is some excuse to call themselves a QF. But that’s not efficient unless the avoided-cost prices are really accurate and even-handed. The most famous problems were NY and CA, which both bought too much “cogen” at prices designed to avoid new nuclear plants. (In a famous FERC decision, the CA avoided-cost prices were determined to be higher than “true” avoided cost, and were ruled invalid. This broke the regulator-dominated planning process, and was a large factor pushing that state toward restructuring.) As long as these prices are set administratively and utilities are forced to buy at these prices, I’m all for increased scrutiny over the kinds of projects that qualify for the must-purchase option. I’m not so sure it’s a big deal any more, though. I think this item has been “on the list” for some of the remaining large integrated utilities for quite some time. This energy bill was an opportunity for them to get almost everything that had ever wanted. They had long wanted PUHCA and PURPA repeal. This is just a PURPA tightening.

  7. You have to read the entire press release, D.O.U.G., not just the small piece shown on the knowledgeproblem website. Or read the entire proposed rule (or the legislation, for that matter, which FERC seems to have just copied nearly verbatim).

    The new proposed 18 CFR 292.205(d) states that “any cogeneration facility that was either not certified as a qualifying cogeneration facility on or before August 8, 2005, or that had not filed a notice of self-certification, self-recertification or an application for Commission certification as a qualifying cogeneration facility under § 292.207 of this chapter prior to [the date the Commission issues a final rule], must also show…[that] the electrical, thermal, chemical and mechanical output of the cogeneration facility is used fundamentally for industrial, commercial, or institutional purposes and is not intended fundamentally for sale to an electric utility….”

    In FERC’s defense, they seem to simply be implementing the plain language of the law that Congress passed, but this could nonetheless bring to an end the certification of large cogeneration facilities.

    And I’m not sure I can share your optimism on the new efficiency rules (yet), since FERC has given no indication of how that law will be implemented. We won’t know that unless they clarify their intentions in the actual rule, or until case law develops to clarify (for those of us bored enough to pay attention) what it means to “show…continuing progress in the development of efficient electric energy generating technology.”

    A good question is whether the requirement that “the electrical, thermal, chemical and mechanical output of the cogeneration facility is used fundamentally for industrial, commercial, or institutional purposes and is not intended fundamentally for sale to an electric utility” could be met by selling the output of your plant not to a utility, but in the retail market to an industrial or commercial consumer that was NOT the QF host. I don’t see why not, at least in states where such retail sales are not prohibited by law. That might provide some hope to larger cogen units.

  8. You have to read the entire press release, D.O.U.G., not just the small piece shown on the knowledgeproblem website. Or read the entire proposed rule (or the legislation, for that matter, which FERC seems to have just copied nearly verbatim).

    The new proposed 18 CFR 292.205(d) states that “any cogeneration facility that was either not certified as a qualifying cogeneration facility on or before August 8, 2005, or that had not filed a notice of self-certification, self-recertification or an application for Commission certification as a qualifying cogeneration facility under § 292.207 of this chapter prior to [the date the Commission issues a final rule], must also show…[that] the electrical, thermal, chemical and mechanical output of the cogeneration facility is used fundamentally for industrial, commercial, or institutional purposes and is not intended fundamentally for sale to an electric utility….”

    In FERC’s defense, they seem to simply be implementing the plain language of the law that Congress passed, but this could nonetheless bring to an end the certification of large cogeneration facilities.

    And I’m not sure I can share your optimism on the new efficiency rules (yet), since FERC has given no indication of how that law will be implemented. We won’t know that unless they clarify their intentions in the actual rule, or until case law develops to clarify (for those of us bored enough to pay attention) what it means to “show…continuing progress in the development of efficient electric energy generating technology.”

    A good question is whether the requirement that “the electrical, thermal, chemical and mechanical output of the cogeneration facility is used fundamentally for industrial, commercial, or institutional purposes and is not intended fundamentally for sale to an electric utility” could be met by selling the output of your plant not to a utility, but in the retail market to an industrial or commercial consumer that was NOT the QF host. I don’t see why not, at least in states where such retail sales are not prohibited by law. That might provide some hope to larger cogen units.

  9. Only industrial, commercial, or institutional purposes are legit?  Not domestic?

    It looks like Climate Energy LLC’s home cogenerator would be frozen out by this rule (unless it falls under some other provision).  I’m not much on these rules and regs; does anyone know if units for the home are addressed anywhere?  Or is this left to the mercy of state regulations?

  10. A home cogenerator is unlikely to get involved in wholesale sales to utilities under PURPA and QF rules. Rather the situation is to a large degree, as you say, “left to the mercy of state regulations.”

    The EPACT 2005 does address this issue just a few sections prior to the QF changes. Section 1251, Net Metering and Additional Standards, provides that each electric utility will have to make available net metering service to any electric customer. Utilities and state regulatory commissions have up to 2 years to initiate related regulatory proceedings, as needed, and up to 3 years (i.e. one additional year) to reach a decision on any regulatory changes needed.

    I’m not a big fan of net metering, but it is a kind of simple ‘rough and ready’ rate design that will help promote decentralized generation and encourage a more active demand side in power markets. This last development would be a good thing.

  11. Well, harumph! You’re right, Charlie, it did say that! But most of the press release goes on to talk about scrutiny over how the thermal output is to be used. Yuck. You’re right, if they take that language literally and to its extreme, then it effectively ends the must-purchase obligation. It would say [taken to the extreme] that the cogenerator should be sized for inside-the-fence use in order to qualify for must-purchase treatment. But the energy available for purchase under such a strict ruling would have to be purely incidental. Jeez.

    I’m not so much worried about the 1,000 MW cogens, as they seem to be pushing the limit of credibility anyway. I’d be interested to know the heat-rate-to-power for a 1000MW cogen plant compared with a stand-alone combined cycle. But a strict interpretation could rule out some very economic but modest over-sizing of the electric plant. That would be a shame.

    In any case, it seems to me that this is important mainly in the bilateral markets dominated by vertically integrated utilities. Generators in organized spot markets don’t really need to have a utility bound into a must-purchase obligation, because they should always be able to sell into the spot market at wholesale, if nothing else. But in the vertically integrated bilateral areas, there is no retail access, so selling at retail is prohibited, even to neighbors across the street.

    It’s pretty easy to see where the political influence for this came from. We may have unwittingly lost a bargaining chip for establishing broader organized spot markets.

  12. Well, harumph! You’re right, Charlie, it did say that! But most of the press release goes on to talk about scrutiny over how the thermal output is to be used. Yuck. You’re right, if they take that language literally and to its extreme, then it effectively ends the must-purchase obligation. It would say [taken to the extreme] that the cogenerator should be sized for inside-the-fence use in order to qualify for must-purchase treatment. But the energy available for purchase under such a strict ruling would have to be purely incidental. Jeez.

    I’m not so much worried about the 1,000 MW cogens, as they seem to be pushing the limit of credibility anyway. I’d be interested to know the heat-rate-to-power for a 1000MW cogen plant compared with a stand-alone combined cycle. But a strict interpretation could rule out some very economic but modest over-sizing of the electric plant. That would be a shame.

    In any case, it seems to me that this is important mainly in the bilateral markets dominated by vertically integrated utilities. Generators in organized spot markets don’t really need to have a utility bound into a must-purchase obligation, because they should always be able to sell into the spot market at wholesale, if nothing else. But in the vertically integrated bilateral areas, there is no retail access, so selling at retail is prohibited, even to neighbors across the street.

    It’s pretty easy to see where the political influence for this came from. We may have unwittingly lost a bargaining chip for establishing broader organized spot markets.

  13. Interesting on-topic item in the news, if you can get Platts. Headline: “US FERC rejects Alliant’s effort to avoid buying power from QFs”

    Alliant is in MISO, and requested to be relieved of its must-purchase obligation on the grounds that a wholesale spot market is now available. I think it was denied on a technicality (failure to notify affected QFs) rather than on the merits of the request.

  14. Looking at the order (in FERC Docket No. EL05-143-000), it says FERC’s decision was based purely on the failure to notify affected QFs. The application was “rejected without prejudice” and can be refiled with the requisite changes.

    This was the first such application since the EPACT passed, so the first time FERC has been asked to act under the new law. FERC announced that all future such applications must identify to FERC all the potentially affected QFs (including names and addresses) so as to ensure sufficient notice as required by the law.

  15. Well, I don’t know the exact statistics, but (although I focused on the 1000 MW plants) I doubt there are many potential QF hosts that could consume 300 MW. Or 100 MW. Or 50 MW. Or 20 MW. There are some at the lower end of the spectrum (and maybe a very few at the higher end), but the numbers of potential QF hosts will be fewer and further between.

  16. My company is presently developing some renewable merchant power plants. All of the plants are presently not in operation. All three will be expanded. I am trying to find out “does this legislation affect renewables that are QF’s”? Our plants do not plan to have a thermal host. Therefore, the sham criteria would not be relevant to us. Comments?
    Finally, does anyone have an idea what the basis of the efficiency is?

  17. My company is presently developing some renewable merchant power plants. All of the plants are presently not in operation. All three will be expanded. I am trying to find out “does this legislation affect renewables that are QF’s”? Our plants do not plan to have a thermal host. Therefore, the sham criteria would not be relevant to us. Comments?
    Finally, does anyone have an idea what the basis of the efficiency is?

  18. My company is presently developing some renewable merchant power plants. All of the plants are presently not in operation. All three will be expanded. I am trying to find out “does this legislation affect renewables that are QF’s”? Our plants do not plan to have a thermal host. Therefore, the sham criteria would not be relevant to us. Comments?
    Finally, does anyone have an idea what the basis of the efficiency is?

  19. My reading of the FERC proposed rule leads me to think the “sham criteria” applies only to cogen QFs, not QFs fueled by renewables.

    The proposed rule will affect renewable-based QFs in that it would reform the restrictions that prevent utilities from owning QFs, and may make other changes, but that is separate from the shame cogen-related changes.

  20. My reading of the FERC proposed rule leads me to think the “sham criteria” applies only to cogen QFs, not QFs fueled by renewables.

    The proposed rule will affect renewable-based QFs in that it would reform the restrictions that prevent utilities from owning QFs, and may make other changes, but that is separate from the shame cogen-related changes.

  21. For renewable QF’s, does the local utility have to buy the electrical output at avoided costs as they do today?

    Further, if their is a local market (such as PJM) for the renewable power, do they have to buy it at the avoided cost?

  22. In a market such as PJM, there should be no need for renewables to have somebody under a must-purchase obligation. Any PJM generator can sell into the spot market at any time, and the LMP at that generator’s node is the avoided energy cost of the system for power injected there. If a generator’s capacity can qualify for a capacity payment, then it can get that, too. PJM doesn’t care what you get your energy from.

    Charlie, my point about the 1000MW cogen plants is that it is very large for cogen. That is, it’s certainly not getting 1000MW off of waste heat. So, it may be that the 1000MW cogen is oversized to the point that it’s efficiency is not much more remarkable than a stand-alone CC. If not, then it’s a sham that doesn’t really deserve must-purchase treatment to begin with. That’s why I’m not much concerned about losing future 1000MW QFs.

  23. In a market such as PJM, there should be no need for renewables to have somebody under a must-purchase obligation. Any PJM generator can sell into the spot market at any time, and the LMP at that generator’s node is the avoided energy cost of the system for power injected there. If a generator’s capacity can qualify for a capacity payment, then it can get that, too. PJM doesn’t care what you get your energy from.

    Charlie, my point about the 1000MW cogen plants is that it is very large for cogen. That is, it’s certainly not getting 1000MW off of waste heat. So, it may be that the 1000MW cogen is oversized to the point that it’s efficiency is not much more remarkable than a stand-alone CC. If not, then it’s a sham that doesn’t really deserve must-purchase treatment to begin with. That’s why I’m not much concerned about losing future 1000MW QFs.

  24. I had to look. It turns out that 1,000MW is the size of the very largest cogen plant, but there is apparently only one of them (according to EIA data). There exists a handful of 700-800 MW cogen plants, most of which have “Energy Center” in the name and are owned by Calpine. Of the largest 7000 MW of QFs, Calpine owns all but one of them (700MW). I really should say that the databases list these as QFs, but I don’t know whether they function as such with must-purchase treatments. Most of it is in CA or TX, both of which have organized spot markets. Calpine seems to have a good bit in AL, as well, though. Most of this capacity is listed as primarily for electric generation.

    These statistics are based on EIA data, but one never knows how accurate or complete any single query is.

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