CARMEL, Ind. — The Reliability Subcommittee’s effort to explore how MISO should address increasingly uneven availability of resources could revive a discussion on developing a capacity market divided by season, stakeholders learned last week.
MISO kicked off its “resource availability and need” effort last month with a white paper on changing availability and an announcement that it would devise specific rules to counter the effects of increasing generation retirements, poor outage coordination, growing volumes of emergency-only capacity and the rising use of intermittent resources. (See MISO Looks to Address Changing Resource Availability.)
During a May 3 RSC meeting, MISO Executive Director of Market Operations Jeff Bladen said the new effort has prompted some stakeholders to ask the RTO to revisit its 2015 proposal to create seasonal capacity auctions, a move that was put on indefinite hold last year after stakeholder pushback.
At the time, seasonal capacity auctions seemed like “a single point solution to a broader set of issues that called for a more holistic approach,” Bladen said, noting that the new effort wasn’t intended to preclude a re-examination of the possible need for the auctions.
Near-term Solutions
Bladen also said several stakeholders urged MISO to focus on near-term solutions to ensure that an adequate amount of resources is at the ready, including improving outage coordination, modifying the rules of emergency-only resource types and creating forecasts that provide a better picture of resource availability in the footprint.
A utility’s cash flow influences the lumping of outages, Bladen said, with fleet operators grouping outages when they expect low energy prices, especially in spring and fall.
“When prices are low, operators tend to take outages. It’s expected,” he said. “This is not as simple as, ‘well, everybody takes outages throughout the year.’ It’s much more complicated than that.” MISO said that most of its planned outages are scheduled less than a week before they are taken.
MISO might turn to a solution that requires more accountability from operators, Bladen said.
“Maybe there’s some expectation for generators to replace themselves [during an outage]? That’s pretty extreme,” Bladen said, stressing that MISO has not seriously discussed that measure.
Bladen said MISO could examine its existing load-modifying resource contracts to include staggering availability times and provide incentives to resources that offer during emergencies outside of summertime.
“Does it make sense to expect non-summer participation when it’s not compensated like in summer?” Bladen asked.
He pointed out that this summer, MISO faces an 80% chance of entering emergency conditions. (See MISO: Summer Reserves Adequate, but Emergency Likely.) He also said that a reduction in zonal resource credit offers has reduced the number of uncleared zonal resource credits in capacity auctions since the 2014/15 planning year.
“While we don’t think the platform is burning, the temperature is certainly rising,” Bladen said. “I want to be clear. The system is not unreliable. There’s just a better chance of emergencies.”
Storage Mentions
The Advanced Energy Management Alliance and other stakeholders called out MISO’s white paper for not explicitly mentioning the help energy storage could provide during tight operating.
Bladen said the omission was deliberate in order to remain technology- and resource-neutral.
“I would say that was intentional. We didn’t intend to reference technologies, but rather we were recognizing the resource availability profiles without going to where solutions could be found,” Bladen said.
Nevertheless, Bladen said MISO must consider the impacts that FERC’s Order 841 may have on its resource availability.
DTE Energy and the Organization of MISO States also asked the RTO to consider revising its loss-of-load expectation (LOLE) study process to include more availability risks associated with its resource mix.
Bladen said MISO envisions more stakeholder discussion before proposing changes to the LOLE study. He said altering study methods could produce a larger planning reserve margin requirement.
“It raises the prospect of socializing the risk by requiring everyone to procure more capacity,” Bladen said. “That’s a choice we can make as a community, but we have to be completely transparent about that choice.”
Consumers Energy’s Jeff Beattie cautioned MISO against risking some of its value proposition to its members by creating an insurance-sharing pool.
Bladen agreed that MISO needs to carefully consider balancing the sharing of resources in the footprint. “I’m glad you raised it because that’s something that needs to be front and center in the conversation,” he said.
He also said the RTO must also investigate shifting loss-of-load risk as part of resource availability. A recent renewable integration study by MISO found that as more intermittent renewable resources join the fleet, the loss-of-load risk becomes shorter but steeper, occurring later in the day after sundown. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)
Developing solutions to MISO’s resource availability issues could stretch well into 2019, Bladen said, and he expected that parts of the solution will be handled by the Market Subcommittee and Resource Adequacy Subcommittee as well as the RSC. He asked for more stakeholder opinion on what approaches the RTO should take.
When FERC set out the requirements for RTOs in Order 2000 in 1999, it put stakeholders at the center of the rulemaking process, guaranteeing that generators, transmission operators, electricity buyers and public interest groups would have a voice in any rule change filed for commission approval.
The stakeholder process works well for many routine issues, but it has shown an inability to reach consensus on major contentious issues, says Christina Simeone, who authored a May 2017 study on PJM’s governance. Simeone, director of policy and external affairs for the Kleinman Center for Energy Policy at the University of Pennsylvania, says some of the shortfalls in PJM’s stakeholder process resulted from compromises made under the Governance Assessment Special Team (GAST) process created in 2009.
Last week, the issues Simeone’s paper raised were back in the news, following complaints by FERC Commissioner Robert Powelson and regulators from Pennsylvania and Illinois over PJM’s decision in February to file two competing proposals for insulating its markets from state-subsidized generation. (See Powelson: ‘Erosion of Confidence’ in Stakeholder Process.)
RTO Insider’s Rich Heidorn Jr. talked last week with Simeone about her study on PJM’s governance, which asked “Can Reforms Improve Outcomes?”
Simeone points to PJM’s lower committees, where generation and transmission owners with multiple affiliates can dominate the voting on proposed solutions. The power dynamic is largely reversed at the RTO’s senior Markets and Reliability and Members committees, she says, because sector-weighted voting often results in buyer-side stakeholders (the Electric Distributor sector and End User sectors) exercising veto power over proposals resulting from the lower committees. PJM’s rules require a two-thirds vote from the members of the five sectors to recommend a rule change to the Board of Managers.
In 2015, more than 77% of the generation needed to meet PJM’s summer peak was controlled, in full or in part, by only 10 companies. Although each company had only one vote at PJM’s senior committees, their multiple affiliates gave them more power at the lower committees. Note: Capacity totals and affiliate counts for companies may have changed since 2015. | Simeone
Simeone recommends that states have a vote through their governors and that PJM review the makeup of its five sectors, noting the dispersion of stakeholders representing the fastest-growing industry segments: renewable energy (Generation Owners), energy efficiency (Electric Distributors, Transmission Owners and Other Suppliers) and demand response (Other Suppliers). She says FERC should require RTOs to re-evaluate their governance processes regularly to comply with the “ongoing responsiveness” principle of FERC Order 719. The researcher is now working on a second phase of the study, expected to be published in the fourth quarter, that will explore the issues further.
This interview has been edited for clarity and length.
RTO Insider: So, it’s been about a year since you issued this report, and you made some recommendations that you acknowledged probably would require a FERC order, because the existing sectors are unlikely to give up whatever advantages they have. I’m curious, have you gotten any feedback from PJM to your findings?
Simeone: I have not received formal feedback … I have briefed the Members Committee on the report, and I’ve briefed various different groups, [including the National Association of State Utility Consumer Advocates and the Organization of PJM States Inc. (OPSI).] (See Policy Churn, Voting Rules Raise Questions on RTO Governance.)
The shortcomings of the stakeholder process I think are starting to gain more attention. I would say there [has] been some general acknowledgement that the stakeholder process could use improvements; I think there’s disagreements on what those improvements could be.
RTO Insider: In your study, you have a continuum that shows, pure market efficiency at the left side, and at the right axis, pure politics. What do you mean by politics in that context?
PJM Decision Making Continuum | Simeone
Simeone: On one side it’s pure market efficiency: What would an academic economist say [about] how the market should be designed? On the complete opposite end of the spectrum, design choices could be made [based on] pure politics. You know, this stakeholder wants this, or this state wants this. The decision that ends up happening on market design falls somewhere on that continuum. And there was always a role for politics to interject in that process, because FERC had always envisioned the role of stakeholders.
Generally, these really controversial issues are about who pays and who is getting paid — and then fairness and power balance issues. And it just sets up this legitimacy compromise. If PJM chooses market design that goes too far toward an efficient market, it is going to be seen as illegitimate to some of the people who have politically motivated priorities. If it goes too far on politics, it’s going to be seen as illegitimate to the people who are prioritizing a competitive market outcome.
So, finding the right place on this continuum is critical to the organization that’s being seen as legitimate. This is very difficult … and the hypothesis is: Could a reform improve the effectiveness of the stakeholder process in finding that sweet spot on the decision continuum that preserves legitimacy?
RTO Insider: Your report mentioned sector self-selection. You said voting in the wrong sector can complicate caucusing and reduce trust among members. Did you hear examples of that in your research, or is this more a theoretical concern?
Simeone: Yeah, I think that this is not … a top concern. I think the bigger issue is making sure the sectors reflect the actual stakeholders in the market. Those five sectors have been in place since the RTO was formed. So, you’re talking about 20 years. In 2009, you had the Other Supplier, and the Generation Owner sector at about 300 members, and 117 members, whereas the other three sectors were between 30 and 60 participants. Fast-forward [to] 2016, and the growth in the Other Supplier [and] Generation Owner sectors has been huge. … This is where all the new market entrants are coming in — renewable energy, demand response, energy efficiency, marketer traders — and they’re all kind of being lumped in to these two supply-side sectors. … As they become more diverse, it’s not clear that any kind of sub-sector has its own voice.
Generation Owners’ share of votes at lower level committees increased from 22% to 28% of the total between 2009 and 2016, while Other Suppliers’ share increased from 55% to 57% — mostly due to an explosion in the number of affiliates. The three other sectors saw their shares decline. | Simeone
To me that’s one of the most important things — making sure the sectors reflect the participants. That will have some impact on sector-weighted voting; you may have to adjust weighting. But getting the sectors right, and then the weights right, is important.
The other thing is looking at some of these legacy deals [from GAST]. At the higher-level committees, only the voting members can vote. At the lower level, it’s the voting member, and all of the affiliates. … There’s going to be a huge supply-side bias through the effect of affiliates at the lower level. … The lower level voting data is completely opaque. You have no idea what’s going on there.
At the lower level, you only need 50% majority to get something passed. Ten companies, through their use of affiliates — [based on] one of the Seasonal Capacity Resource Task Force votes, where I know there was 190 votes cast — in theory, could have prevented anything from passing, because they had 108 votes out of 190 cast. Now, I have no idea if any of these companies voted, let alone all of these companies, but it’s just an illustration.
Of 185 votes by the Markets and Reliability Committee in 2015-16, 158 (85%) were by acclamation and all but one passed (99.4%). But only 12 of 26 sector-weighted votes passed (46%). | Simeone
RTO Insider: Right. And then at the upper level, you’ve got the buy side — End Use Customers and Electric Distributors — which can effectively block a two-thirds vote.
Simeone: Right. … Because the higher-level committee data is transparent, researchers from Penn State have been able to empirically measure the strong voting coalition on the load side. They can’t get anything passed [themselves], but they can block. And so, to me, this is a clear area of reform, where there should not be this splitting of power between the different committees.
Now, I’ve heard some people say, hey, well, this is kind of Congress, where you have an upper chamber and a lower chamber. But in the House and Senate, a proposal can originate from either chamber. Here … all the creativity in the proposal development happens at the lower level. Yes, you need a problem statement approved at the higher level, but all of the creativity — all of the details of the proposal — happen at the lower level.
So, if there were sector-weighted voting at the lower and the higher level, that might be a better alternative — more neutrality, and less bias, in the process. The next area of reform is transparency. And I think that’s critically important.
RTO Insider: Transparency of votes at the lower level?
Simeone: Transparency in votes at the lower and the higher level. Especially when you think about these larger companies, who own generation and distribution, what type of behavior are these firms exhibiting? Could they be using their votes on the regulated distribution side to advance proposals that would [benefit] their generation? You know, that’s an interesting question to look at. But because the data is protected, you can’t determine if that’s going on or not.
RTO Insider: Among your recommendations, you cited fairness issues, and you said to ensure RTO/ISO neutrality, there should be procedures in place to monitor, and correct for behaviors that create preferences, or prejudices. What kind of procedures might be effective at that?
Simeone: I think that’s an area to look into further. There have been some researchers at Penn, led by Cary Coglianese, a professor in Penn’s law school. And he found a variety of projects that talked about regulatory excellence. One of the sub-initiatives in some of these regulatory excellence projects talk about how you monitor organizational culture and how you put management processes and metrics in place to achieve the kind of culture that you want.
FERC has said that the RTO needs to be independent from any market participant. But the RTO also has to be responsive to participants at the same time.
So, what kind of processes can you put in place to acknowledge that, yes, an organization could potentially be biased? I think there’s a lot of work to do to dig further into that topic.
RTO Insider: So, you would put this more in the category of areas needing more research, as opposed to having real recommendations for such procedures at this point?
Simeone: Yeah. And I wouldn’t put that as the top-tier reform at this point. I think it’s important, but not quite as important as things like getting the sectors right, looking at some of these legacy deals, like the split of power, transparency and then the role of the states. I think that’s another really big one.
RTO Insider: Let’s talk about getting greater state participation. That was one of your strong recommendations. Is that related to your observation that it can be difficult to determine what the public interest is because it’s diverse and often conflicted?
Simeone: Exactly. … There are some stakeholders who have strong accountability over the RTO. FERC has this kind of legal accountability, but not the political accountability of the RTO. FERC can’t appoint a CEO to an RTO. Nor can they appoint board members to the RTO.
Transmission owners tend to be the stakeholders that are thought to have the most accountability over the RTO, because their participation is voluntary but needed to run the system — and also because PJM is operating their assets. And then the state has the ability and the right to put policies in place that affect the market. So, these are the stronger accountabilities. And everybody else has maybe comparatively weaker accountabilities.
This raises the question of, does this reduced political accountability benefit certain private interests to the detriment of public interest? And it’s a really complicated question, because what is the public interest? Some people identify [it] as competition, lowest cost, new technologies. Others may say it’s economic development or preserving industry that’s important to my state. Or pursuing this particular environmental goal. And the public interest can change over time.
… So, I think as market design becomes more political, the importance of states participating in the process increases. Not to make things more complex, but actually to kind of integrate those opinions in earlier on in the process. And it is not clear — it’s just a hypothesis — that this would improve outcomes.
I think OPSI should always be a part of the process. …The only problem is that OPSI can only speak [when all members are in] consensus. And clearly the issues in PJM are numerous, and there’s not always consensus on the part of the states.
So, is there an opportunity to have a complement to OPSI, where states can present their opinions on an individual basis, early on in the process? I don’t have all the answers to what that looks like, but I think it’s an important thing to look into. Part of the phase two research will be presenting to the stakeholders a little survey about how these other RTO/ISOs integrate state opinions into the process … and then trying to get stakeholders to think about what they feel would be options for a revised approach.
RTO Insider: You reference the D.C. [Circuit Court of] Appeals’ decision on [the minimum offer price rule]. [See On Remand, FERC Rejects PJM MOPR Compromise.] What’s your perspective on that?
Simeone: NRG [Energy] brought [the appeal challenging FERC’s order] where there was a supermajority stakeholder agreement on design changes to the minimum offer price rule, and FERC —
RTO Insider: — kind of undid the compromise.
Simeone: Not only did they undo the compromise, but they kind of went the other way. … And [the court] basically said, no, FERC, you can’t do that — you can disagree with the stakeholders and kick it back to them. But you can’t renegotiate the compromise.
So, for me, I think it has some interesting implications, because it raises the value of supermajority agreement. Could it spark some behavior that might yield some interesting outcomes? Sure. You know, if there’s certain stakeholders who are really motivated to achieve certain outcomes. Could they strike quid pro quo deals with stakeholders that don’t typically vote in the system? So, for example, the financial traders participate in the process, but not very frequently — only on issues that are important to them. So, if you’re trying to give the stakeholders supermajority, does it then become more valuable to court voters like that to [say] ‘Hey, if you vote for me on this issue, I’ll help you out on your issue.’ That was not explored in the report, because the decision came after.
RTO Insider: So, it raises additional questions. You don’t necessarily see it impacting stakeholder reforms at this point.
Simeone: Right. I think it raises the importance of getting the stakeholder process right. To be clear, there are some people who think the PJM stakeholder process is a complete mess that can never be right. And I disagree with that wholeheartedly. I think it’s really important that the stakeholders are involved. And I think there are many, many things about the stakeholder process that are very strong and critically important to informing these decisions.
But, like anything, the markets have evolved, the stakeholders have evolved, circumstances have evolved. The stakeholder process needs to evolve, and it hasn’t for almost 10 years now. So, it’s time. I think this should be seen as reform consistent with improving the process — which is a normal part of evolution rather than an attack on the stakeholder process, or kind of a judgment that the stakeholder process is somehow bad. I’ve just heard some people just be hyperbolic in their criticisms, and I don’t think it’s warranted.
[Editor’s Note: This story has been updated to include additional filings posted at FERC after RTO Insider went to press Tuesday morning.]
By Rory D. Sweeney and Rich Heidorn Jr.
If it were a Broadway show, PJM’s “jump ball” proposals for protecting the capacity market from subsidized resources would have closed after one night.
Monday was the deadline for the critics to file their comments on PJM’s proposal and the reviews were largely negative. RTO Insider’s initial review of four dozen filings found almost no commenters wholeheartedly endorsing either PJM staff’s capacity repricing proposal or the Independent Market Monitor’s MOPR-Ex plan to extend the minimum offer price rule to existing resources in addition to new entries (ER18-1314). (See PJM Board Punts Capacity Market Proposals to FERC.)
PJM’s plan would allow state-subsidized generators to bid into capacity auctions but ensure they don’t suppress prices by removing those offers in a second “repricing” stage of the auction.
Numerous commenters said PJM had failed to prove the need for the proposed changes, arguing there was little evidence state subsidies, such as nuclear plants receiving zero-emission credits, were suppressing prices. Several commenters said the proposals would increase prices while failing to address the capacity and energy markets’ fundamental flaw: the failure to capture attributes valued by states, such as carbon-free generation. PJM’s state regulators, led by the Organization of PJM States Inc. (OPSI), were unanimously opposed.
Exelon’s Clinton Power Station is one of the nuclear plants eligible for zero-emission credits in Illinois. New Jersey is considering similar subsidies for its nuclear plants.
Hedging Their Bets
While few commenters enthusiastically endorsed either proposal, many offered qualified support for MOPR-Ex. Others hedged their positions.
Dominion Energy, Public Service Electric and Gas, American Electric Power and the Nuclear Energy Institute said FERC should reject both options but that if forced to choose, they preferred PJM’s proposal. While “imperfect,” repricing “is a far more balanced a solution” that respects state initiatives and avoids the possibility of load paying twice for capacity, NEI said.
Exelon opposed both options but called the Monitor’s proposal “particularly indefensible.”
Old Dominion Electric Cooperative — seeking to protect its self-supply resources procured outside of the capacity market — said both proposals should be rejected but that it would accept MOPR-Ex if it were amended to include the municipal/cooperative entity exemption from the capacity repricing proposal. “ODEC’s primary position remains that the commission should avoid layering yet another significant design change onto the already complex [Reliability Pricing Model] construct,” it said.
Consumer advocates from D.C., Maryland and New Jersey also said they would accept MOPR-Ex over repricing, subject to a settlement proceeding or stakeholder process “to further refine” it. The Ohio Consumers’ Counsel took a similar position, saying MOPR-Ex proposal is “less detrimental to markets and to consumers because it is more likely to encourage uneconomic generating resources to retire.”
IMM Joe Bowring acknowledged his proposal “is not perfect” but “is the only choice consistent with markets in this proceeding.”
The PJM Industrial Customer Coalition gave the proposal lukewarm support, saying its members “do not object” to it as “a reasonable extension of the existing construct” but are in full opposition to the repricing proposal.
Several commenters questioned why PJM was pushing for swift action on the proposals while it is conducting its quadrennial review of the variable resource requirement curve and launching a fuel security initiative. (See PJM Seeks to Have Market Value Fuel Security.)
“In light of other, overlapping initiatives currently underway, it is unwise and unnecessary for PJM to push forward with either of the proposed capacity market modifications — particularly when both modifications failed to obtain stakeholder consensus,” AEP said.
American Municipal Power said FERC should order PJM to reconvene the Capacity Construct/Public Policy Senior Task Force “without arbitrary deadlines to complete the evaluation of whether and what types of changes are needed to accommodate state actions.”
“The commission should reject the proposal and direct PJM to reconvene the stakeholder process in its administrative resource adequacy construct, as well as the current quadrennial review process and the novel fuel security proposal,” AMP said.
“Rather than seeking multiple arbitrary commission deadlines and guided processes for the additional work needed to resolve issues with PJM’s proposal, the commission should direct PJM to address the issues with the two proposals and create a supportable proposal that achieves the first principles identified by the commission in the [ISO-NE Competitive Auctions with Sponsored Policy Resources] proceeding.” (See Split FERC Approves ISO-NE CASPR Plan.)
Blow It Up and Start Over
Several companies suggested FERC use its Section 206 powers to craft a solution, though they disagreed on how urgent the problem is.
NRG Energy asked FERC to create “its own just and reasonable capacity market design.”
“While NRG agrees that the existing PJM rules are being overwhelmed by subsidized generation, neither of the two PJM proposals will result in a long-term sustainable market structure,” NRG said. “Inaction is not a viable option.”
The PJM Power Providers Group agreed “the threat … is real” and backed developing a different MOPR “that removes many of the exemptions contained in the MOPR-Ex proposal.”
The New Jersey Board of Public Utilities asked FERC to reject the filing and order PJM to “ensure that any future capacity market revisions are complementary to” attributes sought by the states.
“PJM’s proposals do not aid the commission in its longstanding efforts to harmonize state policies with capacity market planning,” the BPU said. “Status quo is the appropriate action for now.”
The American Public Power Association said the proposals are “further evidence of the ongoing unsuitability of mandatory capacity markets to ensure resource adequacy.” It said, “bilateral contracting or ownership should be supported instead of merchant development of generation resources.”
“APPA agrees that such state policy goals should be accommodated, but raising capacity prices for customers without any assured benefit is not the way to do it,” the association said.
Full Rejection
Consumer advocates from Illinois, Delaware, West Virginia, Kentucky and Indiana said FERC doesn’t have the authority to choose one of the two proposals. “Effectively, PJM is asking the commission to conditionally approve a proposal and then oversee a rewrite of that proposal,” they said.
The Illinois Commerce Commission also questioned FERC’s authority to act on either proposal, adding that, despite “PJM’s lip service to states’ rights … PJM reserves to itself the discretion to cherry-pick which resources are worthy of state policy revenue.”
“State laws that do not seek to impermissibly intrude upon the wholesale electricity market or abrogate a commission mandated rate, properly fall within the jurisdiction reserved to the states and do not violate the [Constitution’s] Supremacy Clause,” the ICC wrote.
Rare Endorsements
One full-throated endorsement came from comments filed jointly by Starwood Energy Group and Direct Energy, who argued MOPR-Ex “is narrowly tailored to mitigate artificial price suppression in PJM’s capacity market while retaining core market fundamentals” and “preserves the ability of both customers and investors to bring new capacity resources, and offer existing economic capacity, into the market on a competitive basis.”
The companies opposed PJM’s repricing proposal and repeatedly juxtaposed the two to argue for MOPR-Ex, which it said “does not thrust the capacity repricing costs onto the market generally.”
The American Petroleum Institute also expressed support, arguing that repricing “effectively provid[es] preferential treatment to high-cost, subsidized resources for capacity commitments that continue to inefficiently displace lower-cost resources.”
“Contrasted with capacity repricing, implementation of MOPR-Ex is straightforward and narrow with all subsidized resources subject to mitigation without exception, and nonsubsidized resources would not be subject to mitigation,” API said in a joint filing with private equity Panda Power Funds and J-POWER USA Development, an independent power producer and developer with 2,700 MW of generation operational or under development in PJM.
LS Power Associates also backed MOPR-Ex saying it is “based on the well-established minimum offer price rule that has long been part of PJM’s capacity market,” while the repricing proposal is “fundamentally unfair” and “irredeemably flawed.”
Rockland Capital argued for the MOPR-Ex with settlement discussions to “ensure that the exceptions from mitigation are tailored to preserve wholesale market prices first and accommodate state interests second.”
The Natural Gas Supply Association was less outspoken in its support but nonetheless urged approving and suspending implementation of MOPR-Ex, then directing those involved to engage in settlement discussions to consider “how exemptions are provided and the appropriateness of unit-specific exemptions, including exemptions provided for units subject to a renewable portfolio standard.”
The group pointed to the nuclear subsidies recently passed in New Jersey as evidence “that the time is now to address state subsidies given that the number of subsidies in the market continue to grow.” (See Exelon to Push for Laws, Rules to Boost Profitability.)
Vistra Energy and its Dynegy Marketing and Trade subsidiary took a similar position, saying “an appropriately designed” MOPR is the best way to support competition.
The Electric Power Supply Association said it opposed capacity repricing but agreed “100%” with PJM that changes are needed.
“The commission should summarily reject the ‘capacity repricing’ proposal … which would enable and encourage state interference with the commission-jurisdictional RPM market, and should instead focus on a MOPR approach, consistent with its recent commitment to ‘use the MOPR as [its] standard solution’ where state policies threaten the organized capacity markets.”
EPSA noted that the Monitor’s MOPR-Ex plan received more support among stakeholders than PJM’s alternative. If the commission does not find MOPR-Ex just and reasonable, EPSA said, it should find PJM’s current MOPR rules are not just and reasonable because they don’t cover existing resources.
Exelon, however, said MOPR-Ex “would prevent state-supported clean generators from clearing at all, replacing them with polluting units. Perversely, that will not just force customers to pay higher electricity prices but also will inflict on customers the additional costs of grappling with the pollution [MOPR-Ex] has created.”
‘Externalities’
Exelon said PJM’s premise — that states making payments to recognize the environmental benefits of renewable and nuclear generators states are “distorting” price signals — is incorrect.
“Sound economics understands that when states tax polluting generators, or pay clean generators for their environmental value, they do not ‘distort’ price signals. They reduce distortions and account for true economic costs and benefits. The only distortion comes from treating clean and polluting generators as the same when they are not.”
The Institute for Policy Integrity at New York University School of Law, a nonpartisan think tank that says it is dedicated to improving the quality of government decision-making, also cited the markets’ failure to value environmental externalities.
FirstEnergy, in a joint filing with East Kentucky Power Cooperative, also agreed that the capacity market is failing to account for externalities — but defined those uncompensated attributes as “resilience, fuel diversity and fuel security.”
“The simple facts are, notwithstanding numerous amendments and market design enhancements through the years, PJM’s wholesale capacity market has never worked as intended. States are compelled to address the needs of their constituents. It therefore should be no surprise that states within the PJM footprint are responding to this long-term market failure by implementing policies that are designed to preserve important generation units and their associated attributes, including generation and zero-emissions attributes.”
They said FERC should reject PJM’s proposals and require the RTO to “develop a holistic solution to the fundamental issues facing its markets.”
Resume Negotiations
Several commenters called on PJM to return to stakeholder negotiations.
Dominion said it opposes both proposals because they extend mitigation to existing capacity resources. “Dominion Energy does not agree that existing capacity resources have the same pricing effects as new capacity resources and warrant identical treatment,” it said. FERC should insist the RTO resume stakeholder discussions to develop rule changes “that focus on actual distortive pricing effects stemming from state public policies,” Dominion said.
Talen Energy Marketing and its fleet of generation subsidiaries argued both proposals are “inadequate” and asked FERC to “direct PJM to engage with its stakeholders in a broader price reform effort, including necessary revisions to the energy market, that would seek to appropriately compensate generators for other, non-price attributes that provide measurable value to the grid.”
States Unanimous
In a rare unanimous vote, OPSI urged FERC to reject both proposals and argued that PJM should “respect the resource choices of state policymakers unless there is a legal determination that a state policy impermissibly intrudes” on federal jurisdiction. State subsidies aren’t impacting the market’s ability to attract resources and provide adequate returns, and PJM’s evidence to the contrary is purely “speculative” and anecdotal, OPSI said.
“Data shows that adequate numbers of generation resources are consistently able to recover their costs, while receiving rational price signals, from PJM markets,” OPSI said. “PJM abandons the cost-minimizing principle and instead proposes an exceedingly complex design change that will place more weight on administratively determined artificially inflated prices rather than actual market participant offers.”
It noted that the Monitor’s State of the Market report found the average age of at-risk units is 42 years while a Department of Energy-funded report found that the average lifespan for coal units in the Eastern Interconnection is 40 years.
“Such findings seem less indicative of market failure, than of rational market signals of entry and exit. … Rather than rising, there is significant data that shows capacity prices should be falling,” OPSI said, noting the results of PJM’s recent quadrennial analysis of its demand curve and recommendations to reduce the expected cost for a new unit to enter the market.
OPSI said the CCPPSTF was flawed because its charter limited it to only consider the capacity market.
The Maryland Public Service Commission said PJM’s proposed changes would “obscure resource clearing, increase uncertainty and raise customer prices.”
The Pennsylvania Public Utility Commission noted that neither proposal received a two-thirds majority at the Markets and Reliability Committee and that both “could result in subsidized resources in one state, significantly increasing market prices in another state.” (See “No Consensus on Capacity Revisions,” PJM MRC/MC Briefs: Jan. 25, 2018.)
It said capacity repricing would incent market sellers to underbid in the first stage of the auction “causing further price volatility” while MOPR-Ex could cause states to pay twice for capacity even as it suppresses energy prices.
The Public Utilities Commission of Ohio said FERC should preserve the current rules “until a direct path to addressing state subsidies, if at all, can be determined.”
“The commission, state commissions and other parties have taken significant steps to resolve perceived capacity market design deficiencies that have not been fully implemented. Yet, in less than three years, PJM is again before the commission proposing another significant overhaul of the capacity market under far less certain circumstances,” PUCO said. “While PJM has provided information on the price suppression effect of subsidies, it has not similarly substantiated the level of penetration of state-subsidized resources that would trigger the need to depart from the status quo with another major overhaul of RPM. Furthermore, the PUCO notes that there is no analysis as to the cost impacts of either proposed option on load.”
The New York Public Service Commission, which is working with the NYISO to incorporate a carbon adder into its wholesale market to accommodate state-subsidized nuclear plants, sought assurances that the commission’s ruling on the PJM proposal “will not serve as binding precedent for other control areas.”
Quad Cities nuclear plant
“This is critical for other control areas to have the autonomy needed to develop market mechanisms that address their regions’ unique circumstances,” the PSC said in a joint filing with the New York State Energy Research and Development Authority.
Environmental Groups Oppose
A joint filing from the Sustainable FERC Project, Sierra Club, Natural Resources Defense Council and Environmental Defense Fund asserted that “PJM wrongly puts the commission in the position of policing the efficiency of state policies.” The proposals put “wholesale market rules on a collision course with states’ core duty to protect the public.”
The filing included a report from “subsidy expert” Doug Koplow that argued energy subsidies “have long been pervasive at both the federal and state level without attendant impacts on PJM’s wholesale markets that have prevented that market from attracting record levels of investment.”
“Even if one state’s policies were to somehow to harm customers in other states, that would not justify commission intervention to countermand those laws where they are lawfully within the state’s authority,” the filing argued.
The Solar RTO Coalition, a newly formed group of solar developers and capital providers, said it is “challenging” to address supply-side subsidies.
“The sheer scope of some of the issues that are associated with how to best incentivize the ‘proper’ development of generation resources … are part of the reason why PJM’s stakeholders were unable to come to a consensus.”
Both OPSI and the Solar Coalition sought to distinguish PJM’s filing from ISO-NE’s CASPR proposal, which the coalition said “was much narrower in scope.”
Ari Peskoe, of the Harvard Electricity Law Initiative, said, “PJM fails to explain why it equates state support for legacy assets with competitive state programs for environmental attributes, even though it concedes that the latter affect wholesale rates ‘to a lesser degree.’”
“Commission approval would substantially expand RTO authority in a field of shared authority. … States did not sign up to have a regional system operator pick and choose among their generation procurement programs, and any assertion to the contrary is unsupportable,” he said. “If the commission approves one of PJM’s proposals, it should expect a steady stream of [Federal Power Act Section] 206 complaints about laws and regulations ensnared or uncaptured by PJM’s arbitrary rules.”
Self-supply Concerns
Dayton Power and Light said either of the two proposals are improvements over the status quo but that FERC should correct “deficiencies” in the proposals by adopting changes to the fixed resource requirement (FRR) option that allows state regulators and regulated utilities to supply their own load with their own capacity resources outside the RPM.
“With the minor tweak to the FRR rules, Dayton believes that market price outcomes will be preserved and states wishing to subsidize varying attributes of generation can be accommodated,” it said. “The only changes needed is to allow for a partial or overlay FRR within a state as opposed to a full zone as the rule exists today. If a state subsidizes 1000 MW of generation for any reason it deems appropriate, it would remove a corresponding amount of load including reserve requirements from the PJM RPM auction.”
In its own filing, EKPC asked FERC to force PJM to change MOPR-Ex’s “public entity” exemption to recognize that the co-op is the only winter-peaking load-serving entity within PJM’s footprint. The proposal uses LSE’s zonal summer-peak demand forecasts to calculate the LSE’s eligibility for the exemption. The LSE cannot own more than 600 MW of generation above the peak summer load it serves. However, EKPC procures generation to cover its higher winter peak, which would put it beyond the 600-MW cap.
The Illinois Municipal Electric Agency avoided comment on MOPR-Ex and focused on criticizing the repricing proposal, which it said would hurt load in the ComEd zone by reducing capacity transfer rights allocated to load “due to the predictable decreased clearing of lower-priced imported generation under stage one.”
The National Rural Electric Cooperative Association reiterated its opposition to PJM’s mandatory capacity market. “However, recognizing that the commission may not at this time unravel PJM’s mandatory capacity construct, NRECA urges that the commission … mandate that any outcome of this proceeding must contain specific exemptions for self-supply by cooperative utilities and other load-serving entities.”
CenterPoint Energy executives said Friday they were “excited” about the company’s proposed acquisition of Indiana utility Vectren, saying it presents them with future growth opportunities.
“This transaction will continue to advance us towards our vision of being the nation’s leader in delivering energy, service and value,” CenterPoint CEO Scott Prochazka said during the company’s first-quarter earnings call with analysts and investors. “We’re excited about CenterPoint’s post-merger future.”
CenterPoint announced the $6 billion deal last month. The combined company would serve more than 7 million customers, operate electric and natural gas delivery systems in eight states and hold about $29 billion in assets. (See CenterPoint Energy to Acquire Vectren in $6B Deal.)
The Houston-based company hopes to close the acquisition in the first quarter of 2019. The deal still requires approvals from Vectren shareholders, FERC, the Federal Communications Commission, and regulators in Indiana and Ohio.
“We are combining two companies with strong capital investment opportunities and rate base growth,” said CFO Bill Rogers. “We believe we also have the right mix of unregulated products and services to meet the customer needs of today and tomorrow. This merger provides us the opportunity to deliver even stronger earnings results than we would as separate entities.”
CenterPoint reported first-quarter earnings of $241 million ($0.55/share), compared with $160 million ($0.37/share) for the same period in 2017, beating the Zacks Consensus Estimate of 44 cents.
Investors reacted to the news by driving CenterPoint’s share price up 6.1% to $26.88 at the market’s open. The stock closed at $26.41.
The combined CenterPoint-Vectren service area | CenterPoint Energy
Prochazka said the Vectren acquisition will lessen the company’s exposure to the midstream space through Enable Midstream Partners, a gas-gathering and processing joint venture with Oklahoma’s OGE Energy. CenterPoint owns a 54.1% share of Enable, while OGE holds a 25.7% limited-partnership interest and a 50% management interest.
“We continue to believe Enable is well-positioned for success,” Prochazka said, pointing to Enable’s earnings announcement earlier in the week in which it reported all-time highs for quarterly natural gas gathered volumes and processed volumes.
That’s not to say CenterPoint isn’t continuing to look for opportunities to reduce its ownership in Enable.
“We need to be very thoughtful and do so in a coordinated fashion with Enable, so we don’t have a negative impact on Enable,” Prochaska said.
Rogers made it clear that CenterPoint will not sell off portions of Enable to fund the Vectren acquisition, saying three times, “We do not intend to sell Enable common units to finance the acquisition of Vectren shares.”
OGE Gets Huge Boost from Favorable Weather
OGE on Thursday credited favorable weather for first-quarter earnings that almost doubled analysts’ projections.
The Oklahoma City-based company reported earnings of $55 million ($0.27/share), compared with 2017’s first-quarter profits of $36 million ($0.18/share). A Thomson Reuters survey of analysts had expected earnings of 15 cents/share.
CEO Sean Trauschke told analysts and investors during a conference call that it was the first time in five years OGE has begun a calendar year with weather that has driven up electricity sales.
“It feels good to have the first quarter behind us with positive weather,” Trauschke said. “Weather changes. It’s not something you can control. What does not change is our execution and focus on getting better.”
Ironically, Trauschke’s comments came in the aftermath of severe weather that hit OGE utility Oklahoma Gas & Electric’s service territory on May 2.
OG&E’s service territory | OG&E
“Tornadoes, high winds, rain, hail, the full complement,” Trauschke said, promising that service would be restored by noon May 3.
OG&E contributed earnings of 16 cents/share, double its performance in 2017’s first quarter. Trauschke said its Mustang Energy Center’s seven new units have already seen “close to 500 starts” and produced more power this year than its legacy units did all last year.
OGE’s revenue for the quarter was $492.7 million, up 8% from last year. Noting the company realizes most of its earnings in the second and third quarters, Trauschke reaffirmed year-end earnings guidance of $1.90 to 2.05/share.
The company’s stock price gained $1.41/share with Thursday’s earnings release, finishing the day up 4.3% at $34.23/share.
FERC on Friday approved the dissolution of the SPP Regional Entity (RE) and the transfer of its members to the Midwest Reliability Organization and SERC Reliability Corp., ending a reliability oversight role that had been a source of concern at the commission and NERC (RR18-3).
The commission found that a proposal submitted by NERC, MRO and SERC in March “reflects the transfers of registered entities will ‘promote effective and administration of bulk power system reliability’” in accordance with the Federal Power Act.
The order terminates the amended and revised delegation agreement between NERC and SPP, effective Aug. 31, and revises the delegated agreements among NERC, MRO and SERC to reflect their new geographic footprints. The transfer is effective July 1.
FERC said it was “satisfied” that the petitioners and SPP “have considered and established mechanisms to mitigate against the risk of material gaps in oversight of compliance and enforcement activities due to the transfer of registered entities.”
Most of the RE’s 122 registered entities have been reassigned to the MRO, with the remainder joining SERC. NERC will assume the compliance monitoring and enforcement of the SPP RTO for two years following the delegated agreement’s termination date, after which it will determine a successor.
SPP was appointed by NERC as an RE in 2007. The RTO said last July it had reached an agreement to dissolve the RE, citing a mismatch between the RE’s footprint and SPP’s. FERC and NERC had both expressed concerns that SPP failed to ensure the RE’s independence from the RTO.
NERC, MRO and SERC filed the joint petition with FERC in March.
The RE said it will address transitional and wind-down costs using its approved 2018 statutory assessment funding. Any funds left over will be transferred to MRO and SERC, allocated according to the transferred load-serving entities’ relative net energy for load.
Coal plant retirements have not caused a shortage of black start resources, but grid operators should consider expanded testing, FERC and NERC said last week.
NERC, its eight Regional Entities and the commission released a study May 2 based on information from a representative sample of nine volunteer registered entities, a follow-up to a 2016 joint report. (See Utilities’ Restoration Plans Pass FERC, NERC Review.)
New York skyline when half the city was in blackout due to a power failure during Hurricane Sandy in 2012. Midtown, with the Empire State Building, is in the background with the darkened East Village and other parts of downtown in the foreground.
“Although some participants have experienced a decrease in the availability of black start resources due to retirement of black start-capable units over the past decade, the joint study team found that the participants have verified they currently have sufficient black start resources in their system restoration plans, as well as comprehensive strategies for mitigating against loss of any additional black start resources going forward,” the new report says. “The joint study team also found that participants that have performed expanded testing of black start capability, including testing energization of the next-start generating unit, gained valuable knowledge that was used to modify, update and improve their system restoration plans.”
A next-start unit is the first generator in the cranking path to be energized using power from the black start generator.
The report recommends that:
Black start generators dependent on a single fuel develop alternative fuel capability or take other steps such as signing firm pipeline contracts. “Furthermore, the joint study team recommends that these black start resource owners work with their regulators as necessary, to develop alternative solutions to address potential fuel constraints.”
RTOs and ISOs consider further study of the adequacy of compensation for black start and other resources supporting system restoration, “including any potential threat or impact on black start resource procurement and retention under current compensation mechanisms.”
Grid operators coordinate transmission and generation registered entities to verify model data and ensure the accuracy of black start simulations. “The joint study team recommends that registered entities performing simulations of their system restoration plans, especially those with cranking path auxiliary loads at a next-start generating unit that are large relative to the black start unit, closely coordinate with generator owner(s) to ensure that the associated modeling data used to perform restoration plan simulations [are] accurate. For instance, the dynamic simulations should include energizing the cranking path and next-start generating unit start-up, using generator and load models that have been verified against electrical data captured during various normal system operations or disturbances.”
Transmission operators perform expanded testing of black start cranking paths, including testing during planned maintenance outages.
The report emphasized that its recommendations — while “appropriate for all registered entities responsible for system restoration” — are voluntary and “not subject to mandatory compliance with the recommendations, separate and apart from any obligations of mandatory reliability standards.”
The report also noted “beneficial practices” used by some that may not be universally appropriate. “The joint study team recommends that registered entities consider incorporating these practices, or variations thereof, as appropriate,” it said.
These practices included:
Coordinating the use of black start facilities across multiple transmission service footprints, allowing a black start unit to aid an adjacent area’s critical load.
Providing additional personnel to staff substations and perform safety watches on transmission lines during expanded testing. “At control centers, additional operators would manage and coordinate expanded testing so that system operators can focus on essential system operations with minimal distractions.”
Having black start generators sign agreements with next-start units to facilitate expanded testing.
Peak Reliability last week outlined a vision for reworking its current structure and reducing costs as it tries to prevent a mass exodus of customers to CAISO.
The reliability coordinator (RC) said the cost reduction will require reducing the size of its board of directors to three members from six, cutting executive jobs, and eliminating some manual and administrative processes. Its current membership and board would need to approve the changes. Peak has been an RC since 2009 and had a $45 million budget for 2018.
Peak’s vision and timeline for Transitional RC | Peak Reliability
An RC provides member utilities services that help them meet NERC standards and requirements, and is entirely different from a market operator. Choosing Peak as an RC would not prevent an entity from joining CAISO’s market, and vice versa.
Peak said its funding amount will fall to $28.7 million if CAISO leaves and all other funders stay; it would be $31.2 million if CAISO remains with Peak under the transitional structure. If CAISO departs, remaining members would see a 10% cost reduction under the transitional RC, but if the ISO remains, all members would see a 30% cost reduction.
Peak spokeswoman Rachel Sherrard told RTO Insider that “the [transitional RC] is not a separate organization. It is how Peak would be structured and funded post 2019. It is not a dramatic change in terms of the tools and services that we as the RC currently provide.”
When asked last week about the likelihood of CAISO remaining with Peak, ISO spokesman Steven Greenlee said, “We are moving ahead with our plans to become a RC and offer those services to other entities in the West.”
Peak would operate under the transitional RC structure in 2020/21 and have a $23.5 million operating budget for 2020. It would offer core RC services that ensure reliability and meeting NERC standards, as well as optional services such as Hosted Advanced Applications and the WECC Interchange Tool, which validates E-Tags and confirms power transactions throughout the region. It would also offer interconnection-shared services that support reliability in the West, such as the Reliability Messaging Tool and Enhanced Curtailment Calculator.
After 2021, Peak and PJM would offer bundled market and RC functions, as well as RC-only services at a reduced price.
Peak CEO Marie Jordan last week provided stakeholders a presentation explaining the transitional structure. She also sent an April 27 letter to the organization’s funding parties, member advisory committee and reliability member representatives, touting its experience maintaining reliability of the entire Western Interconnection.
“Over the past decade, in collaboration with its stakeholders, Peak Reliability has built and operated that RC,” Jordan said in the letter. “CAISO has not. SPP has not.”
Peak said it will issue a straw proposal on May 21 that will describe how the transitional structure could be implemented.
CAISO said it expects to begin shadow operations with Peak in May 2019 and become the RC of record for its balancing authority by the end of June 2019.
CARMEL, Ind. — FERC’s extensive energy storage order has handed MISO’s Reliability Subcommittee a new set of to-dos, including devising a storage capacity accreditation process and deciding whether storage will be subject to a must-offer requirement.
Harding Street Energy Storage interior | AES
The subcommittee will also vet a proposal that will determine whether energy storage owners or MISO will manage the state of charge for resources. The group will additionally consider broader issues around storage, including:
What information MISO needs about batteries to manage real-time operations;
The risks of allowing market participation of energy storage at times when it’s not dispatched; and
Whether MISO should employ reliability improvements to mitigate risks of storage use.
Finally, the group could lay out rules to clarify that energy used for charging is not considered “station power,” which MISO defines as the power a generating facility uses for operating electrical equipment. MISO’s current definition of station power does not include energy used for pumping at a pumped storage facility.
The items were handed down from MISO’s Steering Committee based on recommendations made from the Energy Storage Task Force after discussions on Order 841 and storage’s potential in the RTO.
Harding Street Energy Storage exterior | DOE
At a May 3 RSC meeting, MISO Market Design Manager Kevin Vannoy said the RTO will bring storage participation straw proposals to a June 6 joint meeting of the RSC, Resource Adequacy Subcommittee and Market Subcommittee. He said MISO will vet storage proposals throughout summer to prepare for a December compliance filing.
Vannoy said MISO still hopes FERC will allow it to set a limit on the number of storage resources that can participate in its markets. FERC’s order set a 100-kW minimum size requirement for participation, causing RTO staff to worry that small resources will flood markets with finite capabilities.
The leaders of two key Maine legislative committees told Massachusetts regulators Friday that they oppose a proposed transmission project that would cross Maine to deliver a large amount of Canadian hydropower to Massachusetts.
In a letter to the Massachusetts Department of Public Utilities, the chairmen of Maine’s joint Environment and Natural Resources Committee and Energy, Utilities and Technology Committee objected to Central Maine Power’s (CMP) New England Clean Energy Connect (NECEC) project on economic and environmental grounds.
The Avangrid subsidiary is set to sign a contract this month with Massachusetts for the state’s 9.45-TWh clean energy solicitation, which was awarded to NECEC — a partnership between CMP and Hydro-Quebec — after the original winner, Eversource Energy’s Northern Pass project, was rejected by siting officials in New Hampshire. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
The Maine lawmakers wrote that recent expert testimony to their state’s Public Utilities Commission “indicates that Hydro-Quebec will not produce any additional hydroelectricity for NECEC and will instead divert power it now sells to other markets, such as Ontario and New York, to Massachusetts. In fact, NECEC may result in increased greenhouse gas emissions if markets like Ontario or New York have to use dirty fuel mixes to replace the lost electricity from Hydro-Quebec.”
The lawmakers also faulted NECEC for planning to build its line across the Kennebec Gorge, a “world renowned” whitewater rafting and fishing area.
New England Clean Energy Connect (NECEC) shown in orange | Central Maine Power
“It has not proposed burying any portion of the 53 miles of new transmission line, even at this iconic spot that is critical for Maine’s tourism economy,” said Republican Sens. Tom Saviello and David Woodsome, and Democratic Reps. Ralph Tucker and Seth Berry.
AC Better than DC
Among those testifying to the Maine PUC on April 30 was Stephen Whitley, former NYISO CEO and ISO-NE COO, who appeared on behalf of NextEra Energy Resources.
Whitley said that, unlike other proposed HVDC transmission lines in the region, CMP’s project is completely overhead, and that it would be much more useful to build an AC line “that can be looped, serve load and interconnect other renewable generators.” A DC line would not support interconnecting multiple generators located at different points of interconnection along its route, he said.
In addition, Whitley said, NECEC is not traditional utility transmission, but a merchant project dependent on the market. If contracted by Massachusetts, it will execute only a 15- to 20-year power purchase agreement with the electric distribution companies for a DC transmission line that has at least a 40-year life.
“Thus, even if one accepts the purported needs and benefits CMP attributes to the transmission line for Maine and Massachusetts, there is a cliff on those needs and benefits once the PPA expires,” Whitley said.
Fair and Equal
The Maine lawmakers also faulted CMP for offering “far less to Maine than Eversource offered New Hampshire during the Northern Pass process.”
Maine State House
New Hampshire would have received more than $210 million in benefits from Northern Pass, they said, while the TDI New England Clean Power “project would have resulted in direct payments of $372 million to Vermont for clean water, habitat conservation and clean energy development. CMP has not offered comparable mitigation for Maine.”
They cited other testimony before the PUC that the NECEC project “will suppress existing and future renewable energy generation in Maine due in part to increased congestion on the transmission system.”
The lawmakers concluded: “We are unwilling to sacrifice future development of Maine’s solar and offshore wind industries, which would provide real greenhouse gas benefits and more jobs for Maine citizens, just to provide Hydro-Quebec the ability to market its electricity in Massachusetts.”
Hydro-Quebec partnered separately with Eversource, Avangrid and TDI-NE on three different transmission projects for the MA 83D clean energy solicitation last summer.
California could return to the conditions preceding the energy crisis of the early 2000s if the transition to fragmented decision-making and electricity procurement is not managed correctly, the Public Utilities Commission said in a report issued last week.
The report on California retail electricity choice, entitled “An Evaluation of Regulatory Framework Options for an Evolving Electricity Market,” is meant to guide the discussion as the CPUC, state lawmakers and other entities work to manage the disaggregation of energy procurement from traditional utilities to an environment with much more residential rooftop solar, community choice aggregators (CCAs) and private electricity sellers through the state’s Direct Access program, which allows nonresidential customers to purchase directly from a competitive supplier.
According to the paper, decision-making around reliability, affordability and safety is splintering from central authorities such as the CPUC to multiple entities.
“In the last deregulation, we had a plan, however flawed,” the report says. “Now, we are deregulating electric markets through dozens of different decisions and legislative actions, but we do not have a plan. If we are not careful, we can drift into another crisis.”
The paper examines how electric delivery can remain reliable as the market fragments, particularly from the growth of CCAs. It expresses concerns about reliability, affordability and ability to decarbonize the electric system if the transition is not managed effectively.
| California PUC
During the energy crisis, market design flaws, insufficient monitoring and “gaming” by market participants caused price spikes, collapse of competitive suppliers and rolling outages. The state became the model for how not to manage electricity restructuring and received much attention, particularly regarding the artificial shortages created by the Enron energy trading firm.
Splintering Model
The current model was developed after the crisis, with load-serving entities required to demonstrate each year that they have contracted for adequate energy supply. The paper poses the question of whether there needs to be a single entity responsible for policymaking, implementation and enforcement.
It also explores how new technologies could be financed, how to reduce the use of fossil fuels such as natural gas and how to properly compensate utilities. It also asks whether there should be a state entity to manage “behind-the-meter” generation and other entities that are not under the jurisdiction of the CPUC, as well as evaluating other regulatory models that evolved in New York, Illinois, Texas and Great Britain.
“I think there are solutions to a lot of the potential problems, although there is not a single or a dominant design to target them,” CPUC President Michael Picker told RTO Insider last week. He added that some customer choice models are built around a particular technology such as rooftop solar, battery storage, demand response or natural gas fuel cells that can be obtained through small generator incentive programs.
“We have to do something to address the disaggregation of supply and the splintering of decision-making,” Picker said. About 13% of load across the state is provided through the Direct Access program to commercial and industrial customers.
It’s not the CPUC’s job to get in the way of CCA growth, Picker said, but “we do have to do something to respond to the growing disaggregation.”
CCAs Respond
The CPUC got pushback from CCAs in February when it approved an order implementing a registration process for them along with other changes to the regulatory structure. (See CCAs Oppose CPUC Decision, Process.)
In a statement Thursday, the California Community Choice Association said the CPUC report “wrongly asserts today’s energy system lacks regulation and adequate planning.”
“Highly regulated locally controlled CCAs were designed to help correct the problems from the energy crisis, and they are performing as intended — delivering reliable, affordable and clean energy to local customers, while exceeding the state’s [greenhouse gas] goals,” Executive Director Beth Vaughan said. “It is important to recognize in this report that other states use energy-choice program models that differ widely from those used by CCAs in California.” She said CCAs are committed to “reliability, affordability, decarbonization and social equity.”
The CPUC said the report is not meant to advocate specific policy actions but seeks instead to “jumpstart a conversation.” Comments on the report are due on June 4, which can be filed at customerchoice@cpuc.ca.gov, and the commission has also set up a webpage for the initiative.
