New York Gov. Andrew Cuomo last week announced a push to amend this year’s state budget to speed up the permitting and construction of renewable energy projects.
If the legislature passes the amendment, a new Office of Renewable Energy Permitting will be set up to streamline the siting process for large-scale renewable energy projects.
“This legislation will help achieve a more sustainable future … with a revamped process for building and delivering renewable energy projects faster,” Cuomo said.
The state’s existing energy generation siting process was designed for permitting coal-, oil- and natural gas-fired power plants, dating from prior to the growth of clean energy.
New York in 2011 revised Public Service Law Article 10 to unify siting reviews of new or modified electric generating facilities under one state agency, the Board on Electric Generation Siting and the Environment.
The 100.5-MW Bliss Wind Farm near Eagle, N.Y.
“The renewable energy industry is ready to invest in New York, and a more sensible permitting process that still retains all the environmental protections is sorely needed,” said Anne Reynolds, executive director of the Alliance for Clean Energy New York. “The proposal also includes transmission planning, which is so critical to moving clean power to where it is needed.”
The Climate Leadership and Community Protection Act (A8429), signed into law last July, calls for 70% of New York’s electricity to come from renewable resources by 2030 and for electricity generation to be 100% carbon-free by 2040. It also nearly quadrupled New York’s offshore wind energy target to 9 GW by 2035.
The law’s clean energy mandates also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.
The executive branch proposes that the New York State Energy Research and Development Authority collaborate with the Department of Environmental Conservation and Department of Public Service to develop build-ready sites for renewable energy projects.
“Permitting is a process that involves basically anyone who wants to be involved, which is a good thing, but a challenge for the state,” Sarah Osgood, director of policy implementation at the Department of Public Service, told a conference in 2018. (See New York Plans for Wind Energy, Related Jobs.)
The proposal includes a bulk transmission investment program and streamlined siting process for transmission infrastructure built within existing rights of way, and foresees NYSERDA working with the New York Power Authority, the Long Island Power Authority, NYISO and the state’s utilities to identify cost-effective bulk electric system upgrades and file such evaluations with the Public Service Commission.
The PSC in turn would establish a distribution and local transmission system capital program, with benchmarks and reviews, for each relevant utility.
Consolidated Edison on Thursday reported 2019 net income of $1.34 billion ($4.09/share), down slightly from $1.38 billion ($4.43/share) the previous year.
Net income for the fourth quarter was $295 million ($0.89/share), compared to $331 million ($1.06/share) in 2018.
The company attributed the decline in income to depreciation and amortization expenses increasing 14.6% year-on-year, and taxes other than income taxes going up 8.4% in the same period.
“While meeting many challenges in 2019, Con Edison delivered solid financial results and remained focused on leading the way towards a cleaner energy future for our customers and the planet,” CEO John McAvoy said. “Our recently approved three-year rate plans are essential to helping New York state achieve its clean energy goals, as well as to continue providing safe and reliable service to our customers.”
The state’s Public Service Commission last month approved electric and gas rate plans for January 2020 through December 2022 reflecting an 8.8% return on equity, and the New Jersey Board of Public Utilities approved an electric rate increase, effective Feb. 1., of $12 million for Rockland Electric, reflecting a 9.5% ROE.
The PSC last month also issued an order directing energy efficiency targets and budgets for New York utilities, approving $2 billion statewide for EE programs, heat pump budgets and associated targets through 2025 to meet the goal of reducing electric use by 3% and gas use by 1.3% annually by 2025 (19-E-0065).
Con Ed’s DER meter, ConnectDER | Con Edison
In December, Con Ed completed a study of climate change vulnerability. Considering the increased risk of sea level rise, coastal storm surge, inland flooding from intense rainfall, hurricane-strength winds and extreme heat, the company estimates it might need to invest between $1.8 billion and $5.2 billion by 2050 on programs to adapt to impacts from climate change.
Con Ed is still extremely exposed to Pacific Gas and Electric’s bankruptcy through a large volume of power purchase agreements sold to the California utility. At year-end, Con Ed’s balance sheet included $819 million of net non-utility plant relating to PG&E projects, approximately $1 billion of intangible assets relating to PG&E PPAs, $282 million of additional projects that secure the related debt and approximately $1 billion of non-recourse related project debt. (See PG&E Reports $3.6 Billion Q4 Loss.)
Pursuant to the related project debt agreements, Con Ed reported distributions from the related projects to the Clean Energy Businesses have been suspended.
“Unless the lenders for the related project debt otherwise agree, the lenders may, upon written notice, declare principal and interest on the related project debt to be due and payable immediately and, if such amounts are not timely paid, foreclose on the related projects,” the company said.
FERC’s Dec. 19 order expanding PJM’s minimum offer price rule (MOPR) prompted outrage among some officials in the RTO’s 13-state footprint and shoulder shrugs from others (EL16-49, EL18-178).
Filings by officials in Delaware, Virginia, West Virginia and D.C. show they share some of the concerns that regulators from Illinois, Maryland, Pennsylvania, Ohio and New Jersey expressed last week in a webinar with RTO Insider. (See related story, PJM’s MOPR Quandary: Should States Stay or Should they Go?)
But regulators in Indiana, Tennessee, Kentucky, Michigan and North Carolina — which are only partly within the PJM footprint — say they expect little impact from the ruling. Here’s a summary of where regulators in the nine jurisdictions not represented in the webinar stand.
D.C.
The D.C. Public Service Commission sought rehearing or clarification on the MOPR’s impact on new renewables, new demand response and the district’s default service procurement program, which provides 28% of the district’s electricity, including 85% of residential customers’ usage.
It noted that Maryland and Delaware have similar procurement processes for their default customers.
The PSC said it is unclear if the commission intended the MOPR to apply to the default service procurements. Commissioner Richard Glick said in his dissent that the MOPR could apply to New Jersey’s similar default program, but the PSC noted that the order suggested such programs could be protected under the competitive market exemption or unit-specific exemption.
D.C. also is concerned that the order could make it more expensive for it to comply with district law requiring a 50% cut in greenhouse gas emissions by 2032 and reaching carbon neutrality by 2050.
PJM transmission zones | PJM
It said only 7% of PJM’s power comes from renewables, below the national average (17%) and the shares in MISO (15%), ISO-NE (18.8%) and ERCOT (21.5%).
Using the net cost of new entry (CONE) to set the price floor for renewables could leave PJM further behind, the PSC said. “Thus, we request that FERC consider exempting new renewable resources from the MOPR or treat such resources as an exception — using the net ACR [avoided-cost rate] as opposed to the net CONE for the price floor for new renewables.”
The district also raised concerns about the order’s directive that PJM average the last three years’ DR offers to determine the default offer price floor value for DR that has not previously cleared a capacity auction. A new DR program targeting water heating would have no history, it noted.
It said new and existing DR should have a zero floor price “due to the fact that demand response programs are producing negawatts, not kilowatts.”
“Inasmuch as customer participation in demand response programs is ‘voluntary’ and the programs produce benefits greater than their costs, we do not fully understand why demand response is considered as a subsidized resource. Furthermore, the demand response programs from [electric distribution companies], due to their proximity to load, offer significant reliability values and lead to reduced market power and reduced final price to consumers especially during scarcity hours.”
Delaware
The Delaware Division of the Public Advocate’s rehearing request sought a declaration that the MOPR does not apply to the Regional Greenhouse Gas Initiative, which includes Delaware, Maryland and New Jersey in PJM. Pennsylvania Gov. Tom Wolf is attempting to join also but is facing opposition from the Republican-controlled legislature. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
The advocate expressed concern that the order appeared to limit the MOPR exemption for existing renewable resources based on the PJM Tariff’s definition of “intermittent resources,” which it said does not cover all renewable resources that have generated or received renewable energy credits (RECs) and solar RECs (SRECs).
“For example, Delaware’s [renewable portfolio standard] statute includes geothermal energy technologies, biomass generators, landfill gas generators and fuel cells as electricity generators that are eligible to produce RECs, SRECs or their equivalencies,” it said. “These resources are not intermittent.”
Virginia
The Virginia State Corporation Commission filed a brief rehearing request that referred back to its October 2018 comments in the docket, in which it called for continuing the self-supply exemption for vertically integrated utilities in regulated states. The order exempted existing self-supply resources but indicated new self-supply would be subject to MOPR. (See Is Self-supply Suppressing Prices?)
“Customers in vertically integrated states should not bear the risk of paying twice for capacity, because the states in which such customers reside have made no out-of-market payments to generators,” it said. “What the commission concluded [in 2013] remains true today: Utilities in regulated states have no incentive to attempt to artificially suppress capacity prices, and a properly configured self-supply exemption would fully address the intent of an expanded MOPR.”
West Virginia
West Virginia, which remains fully regulated, has one load-serving entity that meets its capacity obligation through PJM’s fixed resource requirement (FRR): American Electric Power’s Appalachian Power and Wheeling Power, which together serve a little over half of the state’s load. Appalachian also serves significant retail load in Virginia.
The remainder of the state’s load is served by FirstEnergy’s Monongahela Power, which owns or controls 3,580 MW of generation, and Potomac Edison, which owns no generation but is supplied by Mon Power.
Mon Power’s load is almost entirely in West Virginia, while three-quarters of Potomac Edison’s load is in Maryland. Mon Power bids its capacity into PJM and buys its requirements, and those for Potomac Edison’s West Virginia operations, from the PJM market.
“The commission is still reviewing the order, but it appears that the decision to grandfather existing regulated plants that have been selling capacity into the PJM capacity market means that there is no immediate MOPR-related effect on our RPM [Reliability Pricing Model] LSE,” said Susan Small, communications director for the Public Service Commission of West Virginia.
The ruling would not impact the current operating decisions of the AEP companies, but their “option to elect to switch to RPM is now compromised,” Small said.
“We are concerned that new or existing regulated power plants that have not been selling into the PJM capacity market in the past will be subject to the MOPR, a treatment that we believe is unreasonable and discriminatory. This will mean that future options for West Virginia capacity additions and existing FRR regulated plants may be limited.
“By regulating the bid price of only certain unfavored power supply, including regulated power supply, not only will our options regarding how to serve West Virginia load be limited, but the cost of RPM capacity will grow over time because of the discriminatory treatment of resources that are bidding at a price that is considered by some to be too low.”
Indiana
Indiana Michigan Power (I&M), a subsidiary of AEP, is the only investor-owned utility in Indiana operating in PJM and meets its capacity obligation through the FRR, said Stephanie Hodgin, deputy director of communications and media for the Indiana Utility Regulatory Commission.
“Indiana also has rural electric membership cooperatives and municipal electric utilities that may participate in PJM; however, the IURC does not have information on how FERC’s MOPR order may or may not affect them,” she added.
Tennessee
Only a small portion of the northeast corner of Tennessee is within PJM. It is served by AEP’s Appalachian and its affiliate Kingsport Power, according to Tim Schwarz, chief of the communications and external affairs division for the Tennessee Public Utility Commission.
AEP, which serves about 47,000 customers and does not generate any power in the state, is exempt from the MOPR because it uses FRR.
Kentucky
Four Kentucky utilities participate in PJM, including AEP’s Kentucky Power and Duke Energy Kentucky, which use the FRR, and Big Rivers Electric, which is an “other supplier” in PJM but participates in the market through MISO.
Only East Kentucky Electric Cooperative participates in PJM’s capacity market, according to Andrew Melnykovych, director of communications for the state’s Public Service Commission. In its request for rehearing, EKPC called the expanded MOPR a “frontal attack” on practices used by cooperatives for decades.
EKPC said FERC’s ruling was “the most drastic and likely most destructive measure taken by the commission to date” in its attempt to transform PJM’s “resource adequacy market away from a residual capacity auction … to a mandatory sole source for PJM and its LSEs to meet regional capacity obligations.” (See MOPR Ruling Threatens to Upend Self-supply Model.)
Michigan
The only Michigan utility in PJM is AEP’s I&M, which uses FRR.
“It’s a very minimal impact, if anything,” said Matt Helms, spokesman for the Michigan Public Service Commission.
North Carolina
Dominion North Carolina is the only FERC-jurisdictional utility regulated by the North Carolina Utilities Commission. Dominion, which serves about 120,000 customers in the state, uses FRR. Only about 5% of North Carolina’s load is in PJM.
On Feb. 19, RTO Insider held an hourlong webinar with regulators from five of PJM’s biggest states to find out how they plan to respond to FERC’s Dec. 19 order expanding PJM’s minimum offer price rule (MOPR) to new state-subsidized resources (EL16-49, EL18-178).
Illinois Commerce Commission Chair Carrie K. Zalewski; Maryland Public Service Commission Chair Jason Stanek; Pennsylvania Public Utility Commissioner Andrew G. Place; Ohio Public Utilities Commissioner Beth Trombold; and New Jersey Board of Public Utilities President Joseph L. Fiordaliso joined RTO Insider Editor Rich Heidorn Jr. for the conversation.
The regulators were all highly critical of FERC’s ruling — and confident that parts of it will be overturned in the appellate courts — although not all states find it as disruptive as others. (See sidebar: MOPR a Non-Issue for Some PJM States.)
The expansion of the MOPR to existing subsidized nuclear plants is creating major headaches for regulators in New Jersey and Illinois, where nuclear plants are receiving zero-emission credits (ZECs). New Jersey and Maryland, which are planning large offshore wind farms, are upset by the order’s expansion of MOPR to new state-subsidized renewables.
Pennsylvania regulators are concerned that the order will lead to even more over-procurement of capacity. The PUC also said in its rehearing request that the order is arbitrary and capricious because it rejected the competitive exemption to natural gas-fired units not receiving a state subsidy.
The PUC of Ohio said it feared “increasingly complicated MOPR slicing-and-dicing administrative routines” that will disregard the preferences of willing buyers and sellers.
The regulators also expressed a diversity of opinion on how quickly PJM should hold its next Base Residual Auction under the new rules.
The webinar included questions from, and polling of, the audience. It was held the day after FERC issued a tolling order giving it more time to respond to the requests filed last month for rehearing and clarification.
Here’s what we heard. (The transcript has been lightly edited for length and clarity.)
Reaction to Dec. 19 Order
RTO Insider: Let’s go to our first poll question to our audience. We asked what their reaction was to the MOPR order. Were you very happy, very unhappy? Somewhere in the middle?
[Reading results] Not a lot of fans of the order thus far. We’ll let this go just a couple more seconds. At this point, it looks like, the majority of people are on the unhappy side of the coin. And I suspect that may also be the case here amongst our panelists, but let me open it up. So, Chair Zalewsky, tell us about your initial reaction to the order, and did anything in it surprise you?
Carrie K. Zalewski, Illinois Commerce Commission: I’m probably falling on the pretty unhappy spectrum. I don’t want to call the order [a] disaster. … But I think our surprise and disappointment is off the heels of the June 2018 order [in which FERC declared PJM’s existing MOPR unjust and unreasonable but offered a resource-specific fixed resource requirement as a possible option for subsidized resources].
We saw a little bit of hope and some chance in the 2018 order. As you recall, it says it does not take lightly the concerns that states might need to pay twice [for capacity]. This 2018 order [acknowledged] that that was a possibility [and] acknowledged states’ rights to propose valid policy. I think what was most surprising to the Illinois Commerce Commission is that [FERC] noted that it may be reasonable to allow for the resource specific FRR [in the June 2018 order]. And we find out on Dec. 19, that’s no longer the case.
RTO Insider: Who wants to jump in next? Joe?
Joseph L. Fiordaliso, New Jersey Board of Public Utilities: I’d be happy to. And I agree with the chairwoman in her remarks. [My] initial reaction, after they got me off the floor, was devastating. And I’m not going to be as polite as the chairwoman. I’m not going to insult anybody but, wow, were they [FERC] off track. And off track as far as New Jersey is concerned with our initiatives in the renewable energy area can be devastating.
Illinois has same problem as far as ZECs are concerned that we have, but we’re [also] going to have offshore wind pretty soon and this can be expensive; more expensive than we had anticipated if this is not rectified. And New Jersey is willing to go the [extra] mile to try to get some justice here, because it’s that important to our ratepayers.
I think the FERC commissioners who voted for it, as I said, were totally off track. And they did not take into consideration the impact on ratepayers. They did not take into consideration states’ rights. And we have to stand up, I believe, as a region, as an RTO, to get them to reconsider. And I’ve said this before, we’re ready for full frontal assault here against them.
RTO Insider: Thank you, Joe. Chairman Stanek?
Jason Stanek, Maryland Public Service Commission: Similar to both chairs, we were surprised and not in a good way. That decision obviously retreated from its earlier position, where we thought we were all working towards some alternative carve-out mechanism in the FRR market. So, we invested a lot of time and resources only to be surprised with an order that had a very expansive determination in terms of making that [MOPR] floor go as wide as possible with little to [no] exemptions. So, we’ve obviously filed for rehearing; we made note of the fact that FERC failed to consider our alternative proposal called the competitive carve-out auction. We made that a point in our rehearing request, but similar to the other chairs, we’re looking at all of our options right now. We have a work group in the state capitol, taking a look at how we would implement an FRR if we elect to go that route. But we also need time. This is very complicated. We’re working closely with the Market Monitor [in] PJM and our fellow PJM states to figure out what to do next.
RTO Insider: OK, thanks. Commissioner Trombold?
Beth Trombold, Public Utilities Commission of Ohio: Thanks. Ohio has some similar [reactions] to what was just spoken. I guess we never anticipated that FERC would take such a broad action to displace the state’s decisions made through what we believe were lawful exercises of power, or that FERC would fail to demonstrate that the current [capacity] market at PJM … was unjust or unreasonable. So, the order kind of sets in motion this period of uncertainty, which is very concerning to us, and the auctions that we hold here in Ohio [to set default retail generation rates]. And I don’t see how the order improves reliability in the interim or the future necessarily. So those are some of our concerns.
RTO Insider: And Commissioner Place?
Andrew G. Place, Pennsylvania Public Utility Commission: I wholeheartedly agree with what has been said so far. Particularly the breadth of what was defined as a subsidy got our attention. The rejection of the resource carve-out was a significant surprise. The bright line between state and federal jurisdiction authority really to us is eye-catching — that obviating or neglecting the ability of states to make their own choices. And then the disparate treatment between new and existing [resources]. I see no rational basis for the bright line that they drew between new and existing [resources].
Supreme Court or Bust
RTO Insider: Thank you. Chairman Stanek, you said that you’ve got a working group in the capital examining the FRR option. I wanted to ask the rest of you: If this is not overturned on appeal, or scaled back on rehearing, what are the alternatives that you are looking at? Are you considering the FRR option or even something more drastic than that?
Fiordaliso: I agree with Jason: This is a very complicated issue, and one that we are examining very, very closely. And it is one that is going to take us some time, along with our fellow states within the PJM footprint. And I might add, you know, the Organization of PJM States [Inc.] [OPSI] has also settled solidly behind this. And so, I think you have a lot of states and organizations [working to ensure] that something is done to alleviate this injustice, whether that is going to an FRR, whether that’s seeking … the legal avenue. I mean, we’re dealing here with not only the effect on the ratepayers, but we’re also dealing with a states’ rights issue. And the Supreme Court of the United States always likes to get involved in states’ rights issues. So, I wouldn’t be surprised to see this entire order go up to the Supreme Court for final determination. … FERC has stepped over the line, and somebody’s got to bring them back to the other side of that line. And as states, if we can continue to agree, we do have the ability, I believe, to bring [the commission] back to the other side of the line.
RTO Insider: Commissioner Place, let me ask you to follow up with that. And also give us some sense of the timeline. Are you guys willing to wait for the legal process to play out? It could be years before the D.C. Circuit [Court of Appeals], let alone the Supreme Court, rules on this.
Place: Yeah, from our perspective, we would rather see the [Base Residual] Auction take place sooner rather than later. We have implications in our own state for DSP [default service plan] filings that we will see immediate impact on. So, we clearly opined for reconsideration as well as clarification. But in the interim, we say the best course to minimize the damage is to have the auction sooner rather than later. I suspect we are somewhat divergent from our neighboring states on that issue, but it’s the short-term impact that’s got our attention in Pennsylvania. We are well along with compliance with the Alternative Energy Portfolio Standard. So, the impacts for us are on the out years, and they’re significant. So, I’m not minimizing that the rule is deeply flawed. But we have to judge what’s the bigger near-term impact. And for us, the near-term impact is largely if we delay the auction any further than necessary, and 2020 would be ideal for us. [Pennsylvania’s Alternative Energy Portfolio Standard requires that by 2021, 8% of electricity come from Tier I energy sources — including solar, wind, low-impact hydro, geothermal, biomass, coal-mine methane and fuel cells — and 10% from Tier II energy sources, including waste coal, distributed generation, demand-side management, large-scale hydro, municipal solid waste, wood pulping byproducts and integrated gasification combined cycle coal.]
RTO Insider: Just to follow up, commissioner, when you say the out years, is there a threshold? Is it three years, five years?
Place: There is no good, bright line. It’s this continuum, the drip, drip, drip, that will see continuing oversupply, which will damage particularly energy market prices. So, the damage [is] to generators, [who are] going to be dropping out because, for example, the nuclear units get much of their revenue from [the capacity market]. They will start to be bitten more and more. And you’ll get this greater and greater overhang of capacity that’s being built outside of the market. So, it’s a continuum. I’m not sure whether there is an inflection point out there. It’ll just worse year to year. So, it’s difficult to answer, but I’m thinking five years out, and certainly no more than 10 years out, you will see substantial damage from this rule if it if it remains in place. Although I agree with President Fiordaliso [about] the certainty that this will go through the courts.
RTO Insider: Thank you, commissioner. Commissioner Trombold, I’m sorry, you were trying to get in there.
Trombold: I just wanted to piggyback on Commissioner Place’s comment about the auctions occurring sooner rather than later. We were the only two OPSI states that both agreed to have the auction sooner rather than later. And in terms of the FRR in Ohio, no decisions have been made on that yet. But the companies would be the ones to elect the FRR in Ohio. So that’s just something I wanted to point out.
RTO Insider: You raise a very good point. When we talk about states [potentially] pulling out of the capacity auction, that does oversimplify it. If you wanted to direct your utilities to either go that route or not, what kind of control do you have to be able to do that?
Trombold: I’d have to double check with our legal eagles. But I believe that we do not have specific control over the FRR election. I don’t think that would be something that commission has powers to order.
RTO Insider: Thank you. Chair Zalewski, want to weigh in on this one?
Zalewski: Yeah, sure. In Illinois, we’re in our spring legislative session, which started in January and ends May 31. There have been bills previously filed that are circulating that do speak to FRR. This was before the order came down. It was in anticipation. So, these were, bills that were filed in previous spring sessions. Our governor did say in his State of the State [address] that his energy bill is at the top of his list. Now whether that includes an FRR is to be determined. He’s not taken an official stance on that. And I think he’s wise because his office as well as our office is waiting for some of these [MOPR] values to come down to really have an understanding of the impact. And obviously we’re hoping for more clarity. In our request for rehearing we asked for clarity, which I’m sure everyone — all other chairs and commissioners did as well. So hopefully that will shed light on it. With regard to the timing, we matched up with the letter that was filed on behalf of OPSI, which was a kind of a balanced approach where [the auction would be held] at least 12 months from the PJM compliance filing order, but not more than May 31, 2021. The idea being that’s enough time for the states to react — and maybe that’s not enough time, but some time for the states to react, whether that be a change in the renewable portfolio standard and how we address that or we go a different route — but not too much time. And I think this point was raised as well. These [generating] plants need to have an understanding of their revenue stream. So, the closer the auction is to the delivery year, I think it gets more and more complicated for them to make business decisions. So that’s how we landed on that timeline. It’s not perfect, but we had to pick something.
Impact on Renewables
RTO Insider: Thank you for those answers. I should update you. This morning the Market Implementation Committee had a special session on the MOPR ruling and much of the discussion was on potentially compressing the auction schedule from nine months to six months. There are three deliverables that happen in the nine-month time frame that they’re discussing compressing into six months, and that generally seemed to be fairly well received [by stakeholders]. I can say that the suggestion by Maryland that the auction not be held until [May] 2021 was deemed, quote, “crazy” by one generator, who said, you know, ‘We’re making investment decisions here. We need to move on.’ [See related story, PJM May Compress BRA Schedule over MOPR.] So, this is certainly an issue that we will be tracking going forward.
I’m going to pause for another poll here. This has to do with the impact of the MOPR on new renewable generation: Assuming it’s not overturned on appeal or rehearing, will it have a big impact, a small impact or medium impact? Of course, I didn’t really qualify over what time frame I was saying. So, some people may be wondering about that. But maybe you all can comment on that once we complete the poll.
[Reading results] OK, about half say it’ll have a big impact. About a third say a medium impact, and about the fifth say a small impact. So, what say you panelists?
Fiordaliso: I would say big impact. … Any renewable [that] comes online is going to face this situation. And we have 7,500 MW of offshore wind scheduled by 2035. We have ZECs that are going to be on the chopping block. Any new renewable that we’re not even thinking about probably today that comes online will be severely affected in my mind. This is the federal government’s way of saying that, ‘You want to do clean energy? Fine, but we really don’t support it. So, we’re going to throw obstacles. We’re going to throw barriers in front of you to make it more challenging.’ Instead of making it less challenging, so that we can proceed in a prudent, logical fashion to mitigate the effects of climate change. We don’t need these roadblocks. What we need is cooperation.
Stanek: I agree with Joe. We know that FERC crossed the line under Section 201 of the Federal Power Act, which delineates the wholesale markets from the retail markets. To your question, I think you picked up on the area where we could have had more clarity. Where are we going to see this [impact]? In the near term? Years further out? If we look back at the last auction that was conducted in May of 2018, only about 1%, a little over 1% of the cleared capacity was renewables. And I suspect that that will continue on for the next couple of years. But this problem will magnify as we go further out, and then perhaps the rate impacts will be several billion dollars. Commissioner [Richard] Glick, I believe he estimated $2.4 billion annually. So, whether it happens next year or 2022, we’re going to see the effects begin to ramp up within the next, I would estimate, two to three years.
Fiordaliso: I would agree with that, Jason. And the major effect on New Jersey will probably be the next year and a half to two years. I would expect the generators to say that Maryland’s stand on this is crazy. However, I don’t think it’s necessarily crazy.
RTO Insider: Joe, let me follow up on something you said. [FERC] Chairman [Neil] Chatterjee has said this is all about protecting the markets. You suggested that this is really a manifestation of the Trump administration’s hostility to clean energy policy. Do you not buy what Chairman Chatterjee is saying? Do you really think this is just a naked political move?
Fiordaliso: Honestly, yes, I do. Why present these kind of challenges if the states are trying to do programs that hopefully will mitigate the effects of climate change? Why throw obstacles in our way? The federal government is doing nothing regarding climate change. It’s up to the states to do it. We’re willing to do it. And we’re willing to prudently move down this path of a carbon-neutral environment by 2050. If the federal government doesn’t want to join us, fine, just get out of our way.
RTO Insider: Commissioner Place, would you like to weigh in on that?
Place: Yeah, happy to. From a parochial perspective, our Alternative Energy Portfolio Standard is essentially flatlined where it is. It’ll hit its peak in 2021. So, our parochial impact for our renewable portfolio is marginal. Plus, we have [an] overbuild, except perhaps in some in-state solar, to meet the requirements through 2021. … But the question was PJM-wide and very clearly, I would agree that this would have draconian impact on states’ desires to build renewable power. And I think the problem I have with the ruling is that it, it doesn’t tackle the problem. As I noted earlier, you’re going to see states are going to build regardless. New Jersey is going to build offshore wind; Maryland’s going to build offshore wind. Those are going to happen. So, you’re going to have more states potentially doing FRR. You’re going to have this great overhang of excess capacity being built outside the market. You’re going to see that deleterious impact on energy market prices, all of which is going to make the current impact from state-supported resources in the market pale in comparison to what you will see five, 10 years from now. It’s a moment where you really do need to go back to square one and think about how this mechanism should be done. If you care about the integrity of the market, you’re just simply not tackling the problem or the issue that you’ve identified. I wholeheartedly agree, the state’s ability to choose their own path forward should be in this way sacrosanct, other than not distorting the market. But you can clearly develop mechanisms that accomplish both the state’s desires to have the portfolio of their choice, but also ensure that capacity markets — or if it’s a totally new construct — [obtain] capacity. Or do we go back to essentially an energy[-only] market formulation? Those solutions are all achievable versus what was put on the table here, which does look like a very pointed, very one-dimensional attack, on renewable choices by states.
Impact on Coal, Gas
RTO Insider: Let me go to a related question that was posed by one of our listeners, Michelle Bloodworth [CEO of coal trade group America’s Power]. She asked: ‘What impact will the MOPR have on the coal fleet?’
Stanek: I would suspect in the near term, this would be a net positive for any of the fossil resources, whether it be gas or coal. So, I suspect that those sectors viewed the December order rather favorably.
Fiordaliso: Yeah, I would concur.
RTO Insider: Commissioner Place, do you have any perspective on that, given the Pennsylvania’s spot in the fossil generation?
Place: I agree. Certainly in the near term, it’s advantageous. But … there are probably greater economic forces driving us away from coal consumption. So, they’ve got substantial headwinds. But this is, in isolation, sort of a short-term net benefit to the coal generators, and as Chairman Stanek pointed out, to all fossil generation.
Carbon Pricing
RTO Insider: A couple weeks ago, PJM appeared on a forum and suggested that really the answer to this dilemma — this constant conflict between state and federal policy over environmental policy and emissions — is a carbon price. (See PJM: Carbon Pricing the Answer to Subsidy Dispute.) And clearly, that is a very complicated and potentially divisive issue. But I wanted to ask you, what do you think your state’s appetite is for a carbon price? Is it a realistic idea? We know that the New England states, while they have RGGI [the Regional Greenhouse Gas Initiative], the bigger states and more aggressive states were unable to persuade some of their smaller more conservative states to up the carbon emission targets as part of their approach to the capacity market. So, do you see this as either feasible or acceptable to your state?
Stanek: Well, as a RGGI state … we see the benefits of having a carbon cap-and-trade program here. I think what was laid bare in the Dec. 19 order was the fact that we don’t have any value on carbon, whether at the federal level or at the PJM level. And if we did, we’d be able to [put a] value on our preferred resources and we’d be out of this mess entirely. But as a RGGI state along with New Jersey … we see some benefits. But we do have issues with leakage regarding some of our neighboring states. And that’s a problem with having voluntary constructs such as RGGI.
Zalewski: Illinois — we’re not a RGGI state — does not have a broad carbon price. However, the state has employed carbon prices for legislation. For example, customers pay on their utility bills for ZECs — they pay $16.50/MWh — and also through a renewable portfolio standard. And so, through policies like this clean energy is given a priority over dirty generation. I’m not aware of any additional legislation as I sit here right now of potentially going to moving towards RGGI. I think everyone right now is reassessing and seeing if it makes sense. It’s not clear obviously how RGGI would be MOPR’d. … I think that there are people thinking through all options. But as I sit here today, that’s going towards a RGGI in Illinois, to my understanding, has not been put on the table for legislation.
Place: And if I may jump in, as most everyone I presume on this call is aware, Pennsylvania, under an order by our governor late last year, will be linking to RGGI. The rule is expected to be before the Environmental Quality Board in July of this year. And so that’s the extent of our conversation within the commonwealth on pricing carbon. We did have the conversation last year — the nuclear debate [over ZEC-type subsidies]. I can’t comment on whether that will resurface and whether that is another piece of this.
RTO Insider: I should mention in Pennsylvania, for context, there was a hearing last week in the legislature, the Republican-controlled legislature, which is not in favor of joining RGGI. And they made sure that not a single pro-RGGI witness apparently testified. (See Critics: Pa. RGGI Hearing Stacked with Detractors.) The legislature believes that the governor does not have the authority to enter RGGI. Does the PUC have an opinion on that at this point?
Place: The PUC does not have an opinion on that. But I would steer it towards the governor’s belief that he has the authority to do so. And when I did watch the legislative hearing last week, [I] agree with you that … there was no balance.
Fiordaliso: New Jersey, Rich, just recently rejoined RGGI after many years of absence. And we’re very happy to be back in RGGI. And generally speaking, I think the concept of carbon pricing is very much in line with our clean energy goals.
RTO Insider: Commissioner Trombold, did you want to weigh in on this, or is this a hot potato?
Trombold: [laughs] Well, yeah, we’ve talked about carbon pricing probably for the last 30 years, and it hasn’t really happened yet. I think there’s many coal states in PJM, and we’d have to get all the PJM states on board in order to do something like this. I think at the end of the day, every state has to do what’s in their best interest. So that’s why the PUCO hasn’t really weighed in on any kind of carbon pricing at this point.
RTO Insider: I do note that the PJM has actually said that they wouldn’t need all of the states to join. But it certainly would be a lot more complicated if you’ve got some states in, some states out, referring to leakages as Chair Stanek mentioned.
Place: I should jump in. The governor’s executive order on RGGI did contemplate leakage and border adjustments. So that that’s yet to be determined on what that might look like — emissions leakage or economic leakage. That’s clearly on the menu here in Pennsylvania.
Economic Impact
RTO Insider: I’ve got another question here from Nancy Bagot, [senior vice president] from EPSA [the Electric Power Supply Association]. She says: ‘Many clean energy resources have become increasingly cost competitive, if not more competitive than existing resources. Therefore, most may clear [the capacity auction] using the unit-specific exemption. How are states making the assessment that this will have a great impact? Also, offshore wind is so expensive comparatively, it could never clear a regional auction. So how is it disadvantaged? As states follow their own paths, how is reliability being ensured on a system that is physically regional?’
I’ll let you guys jump in on to any or all of that.
Fiordaliso: I’d like to jump in, Rich. I think renewables in general, initially are expensive. But I can build a solar installation today for half the price of what it would have cost me back in 2008. I think we’re seeing prices, price per kilowatt-hour, decreasing as renewables become more prevalent. I think the offshore wind is going to follow the same pattern.
And I think one of the things we don’t really put a lot of emphasis on, and we should, [is] the economic impact of renewable energy. As an example, in the state of New Jersey, we have over 7,000 people working just in the solar industry. We expect thousands more to be working in the wind industry. And all of the ancillary businesses that feed into you know, along the East Coast here. States like Maryland and New Jersey can be supply chains for offshore wind throughout the Northeast. So, we rarely look at the economic advantages. All we do is look at the economic disadvantages with offshore wind. I submit the advantages certainly outweigh the disadvantages when we take into consideration not only the supply chains and things of that sort and the ancillary businesses that will grow around wind and solar, etc. But also, can we afford not to spend the money to mitigate what 98% of all scientists tell us can be a catastrophe in years to come?
Zalewski: [In] Illinois, I think the immediate answer is we’re just collecting as much data as we can and trying to keep current with the information coming at us with things like the MOPR [pricing] data. In fact, our General Assembly just called a subject matter hearing this Friday to discuss this, the impacts of the MOPR. And we’re having the Market Monitor coming to speak to our legislators. … The Market Monitor has put out a report, they indicate that … the MOPR may not be so high that some of these resources can’t clear [in the auction]. We also know, capacity revenues for renewables are not as much of an impact on revenues in total as compared to nuclear.
… And I agree with the economic impact. In Illinois, we have a preference for in-state renewables. The legislation we’re under is the Future Energy Jobs Act. The ‘J’ stands for ‘jobs.’ All renewables must be in-state. … I agree, it will be a big hit to the state if we do see renewables taking a backslide.
Stanek: I don’t think the question that was asked is an unreasonable one: Can we use the unit-specific exemption for some of these clean technologies that are more cost competitive? But there is recognition — and I think the questioner was right — offshore wind is terribly expensive. But states such as Maryland have passed laws to provide these subsidies, these RECs [renewable energy credits] to the wind developers. And we recognize that it’s going to cost more than, let’s say, a gas plant or a coal plant to operate. But that’s the state’s decision. And under Section 201 of the Federal Power Act, states determine their resource portfolio, including the type of generation that they want to see in their mix. So, I would I push back gently on Nancy’s question. I think there will be some use of the unit-specific exemption, but I don’t think it’s going to be all that great.
Impact on Demand Response, Energy Efficiency
RTO Insider: Let me move over to another question from the audience. And this is a question that is actually being discussed right now, by the Demand Response Subcommittee at PJM. That is: What is the effect of the order on the EE [energy efficiency] and DR [demand response] programs of your utilities?
Stanek: At this early stage, it seems like EE and DR would not be exempted under the Dec. 19 decision. So, we’re still waiting to see the effects. We haven’t spent as much time on those two areas of generation [as] some of the others, but it’s obviously going to have an impact on both.
Place: That was one of our [requests for] clarification. I wouldn’t bet the house that DR and EE are not going to be caught up in this. So, for our Act 129 [energy efficiency] programs, we are very much looking forward to a clarification and to ensure they are not going to be MOPR’d.
Fiordaliso: All I would say is that it’s too early and there have not been clarifications regarding certain areas. And so, we’re looking at a wide variety of alternatives, us here in New Jersey, and waiting for some of these clarifications — if we ever get them.
Zalewski: We have the same concerns, and we made note of that in our in our request for rehearing and request for clarification. It’s also unclear the distinction between new and existing demand response programs too. So just adding on to the questions waiting for answers from FERC.
Stanek: I think the point that Joe just made is, if and when we ever get [answers]. We still have a rehearing request outstanding from the June 2018 order. Now we have rehearing [requests] from the December 2019 order. And we found out just yesterday that rehearing, not surprisingly, is going to be tolled, but until when? 2021? It could be a while.
FRR Option
RTO Insider: Hopefully, we’ll get some clarity on that from the D.C. Circuit; I believe next month they’ve got oral arguments in a case that deals with the tolling orders in Natural Gas Act proceedings. A lot of people seem to think that will also have some application on FPA cases also. I have a question here from Kyle Vanderhelm [director of fundamental analysis at Tenaska]: ‘Most panelists seem to be have been OK with a resource-specific carve-out FRR. Why is that workable and FRR as it stands not workable? It seems that FRR for an entire region maybe more straightforward than one-off carve-outs.’
Anybody have any insights on that?
Fiordaliso: I don’t have any insights. I would only say that we’re still exploring. It’s early yet. … We’re still exploring: Is that the right way to go? Is it the most efficient way to go? And so, we have not in New Jersey come to that determination.
Stanek: In Maryland, I would say that we’re trying to evaluate the pros and cons right now. And there are cons. We will need some authority to provide some oversight of any FRR, whether it be one utility or all of our utilities in the state. And I have to ask myself the question: Will it be PJM subcontracting? Will the PSC be able to handle that in-house? What do we do with retail supply that’s about a fifth of the book in the state of Maryland? Will [they] be able to contract with their own resources? So, there’s more questions than answers. We’ve been an early advocate of moving the auctions out by a year, and one of the reasons is because the Dec. 19 order made clear that FERC is not likely going to rerun any auctions. So, we’ll have to live with the next auction results. That’s the reason for our [request for] delay, whether it be crazy or not.
Legal Vulnerabilities
RTO Insider: Alright, let me go to our next poll question: ‘How will the MOPR ruling fare in the appellate courts? Very well: It will be upheld in its entirety. So, so: There will be moderate changes to the ruling. Poorly: The court will largely reject FERC’s order.’
Stanek: I would just jump in quickly and say that the courts have consistently recognized state authority over generation matters. And we’ve seen a recent line of cases — whether it be EPSA, ONEOK or Talen v. Hughes, which we, Maryland, did not win, but it provided a precedent that defines the line between the feds and the retail regulators and the sense of cooperative federalism that we did not see into December order. So, I would be rather bullish here and choose option [three] ‘poorly.’
RTO Insider: Alright, well, there aren’t too many people [responding to the poll] who think it’s going to survive unscathed. Did anybody else want to weigh in on that subject?
Fiordaliso: And ultimately, it’s gonna wind up where? The Supreme Court.
Place: Yeah, and, and to me, just looking at it sort of piece by piece, particularly the disparate treatment of new versus existing [resources]. I think there’s chunks in here that I just don’t see doing well [on appeal] and being shown to be just and reasonable.
Zalewski: And there’s another layer: … not only the disparity between new and existing [resources] but the disparity between vertically integrated and deregulated states and how their resources are. And again, that leads back to a state’s decision to be become deregulated. So, we’re just circling back to where we started — the overstepping of the federal government [on] states’ rights. There’s lots of layers to it.
Place: Also, thinking about the disparate treatment between state subsidy and federal subsidy — I don’t see how a court will look at that and think that that’s a rational outcome.
RTO Insider: We have another question here from Rob Gramlich. You may recall a few months ago, Rob made some headlines with a study that found that an expanded MOPR could greatly increase [capacity] costs. He asks: ‘In other regions such as SPP, the Regional State Committee makes the high-level policy calls on resource adequacy, which FERC put in place at its start-up, recognizing the states’ authority. The idea was raised at last fall’s OPSI meeting. What do you think of that as an additional option for states to make sure wholesale markets and state policy fit together?’
Stanek: [laughs] Leave it to Rob Gramlich to come up with a question like that. Let me think about that.
RTO Insider: [pause] OK, I think Rob stumped the panel. I should mention also that on tomorrow’s agenda for FERC there is an order in FERC Narrows NYISO Mitigation Exemptions.]
Let me ask: Illinois in its rehearing request said that state policies are not subsidies but compensation for clean energy resource attributes to address PJM’s failure to account for negative environmental externality. State policy initiatives ‘improve the efficiency and price signaling aspects of PJM’s capacity auction process by accounting for the social cost of carbon.’ Can you elaborate on that Chair Zalewski?
Zalewski: Our first concern is with the term ‘subsidy.’ It’s a pejorative term, suggesting that subsidies move away from economically efficient solutions. However, we talked a little bit about this previously. This is a classic example of market failure when pollution costs are not addressed. FERC and PJM have repeatedly failed to address this market failure. And so, I think that our point is that when these pollution costs are not accounted for, markets don’t produce economically efficient solutions.
RTO Insider: We have a one more question here. Again, Kyle VanderHelm asks: ‘Do you see value in having a competitive capacity market? If so, are you supportive of alternative approaches to avoid price suppression from subsidized capacity?’
Stanek: Absolutely.
Fiordaliso: Yeah.
Place: The challenge I’ve long had is that the capacity price is a contrived mechanism. It’s a construct, versus the energy [price], which is market driven. So, although we’ve seen value in the capacity market, PJM is historically over-procuring, and it is flawed in that it’s an artificial mathematical construct. So yes, there’s some value there. But are there better ways to do it? I would argue yes.
Zalewski: I take umbrage with the second part of that question about market suppression. That was one of our points in our request for rehearing — that there’s no evidence of price suppression. … But yeah, I echo that [there] could be a good alternative.
Trombold: Ohio agrees with what the chair just said. You know, there’s lots of things that cause price suppression in the market, not just some kind of state support. I mean, there’s things like bidding behavior, forced outages, capacity imports. And we put that all into our rehearing requests as well.
Place: And if you look currently, if you go down that track of price suppression, the impacts currently in the market are small. You’re chasing a solution in search of a problem. And yes, you can see over time that the price suppression may become an issue with state resources. But I’m not buying that it’s a house-on-fire problem today or even tomorrow.
And I did also not want to let the Illinois carry the full burden on the points about subsidy versus internalizing big external costs of pollution. I’ve not taken a shot at fossil — I used to work in natural gas business. But clearly, if you’re a resource that’s able to emit without monetizing the cost to society of those emissions, then that is an inverse subsidy. So, I think it’s disingenuous to simply go down this route that says that states are doing something untoward by trying to internalize the price of those emissions.
RTO Insider: Well, thank you. I really want to thank all of you for participating today. This was a really, really good conversation. We’re about out of time. We have one more [poll question]. OK. You guys have already weighed in on this: ‘What is the biggest legal vulnerability in the MOPR ruling? Exempting future resources?’ All of you cited these examples. ‘Exempting future federal subsidies but not future state subsidies? Eliminating the exemption for future supply-side resources and FERC’s jurisdiction over state resource choices?’
[Reading results] The jurisdictional issue is very, very popular. This one’s a landslide.
Well, thank you very much. And I also want to thank the audience for its participation. We had some great questions and some great feedback on these questions. We of course will be following this on a daily basis up at PJM.
SPP staff are working with both MISO and Associated Electric Cooperative Inc. (AECI) to develop coordinated system plans (CSPs) in the search for joint projects, staff told the RTO’s Seams Steering Committee last week.
Neil Robertson told the committee during its meeting Thursday that the RTOs are “not necessarily” on the same page as to what the 2020 CSP looks like, but that SPP would like to conduct a study similar to last year’s. The RTOs studied potential interregional projects using their regional models in 2019. However, as when they collaborated on CSPs in 2016 and 2018, SPP and MISO were unable to reach any agreements.
The wild card, Robertson said, is the limit MISO faces on regional directional transfers (RDT) between its northern and southern regions over SPP’s system.
Under the terms of a 2015 settlement agreement with SPP and other parties, MISO is limited to 1,000 MW of contracted, firm transmission capacity, with access to additional non-firm service capped at 3,000 MW in southbound flows and 2,500 MW northbound. MISO is keen on modifying the RDT arrangement when the settlement agreement expires in February 2021, and both RTOs have or will be conducting studies on the constraints. (See Interregional Projects May Become Reality for SPP, MISO.)
MISO South’s connection to MISO | MISO
“We’re trying to figure out how the RDT study melds with doing a typical CSP,” Robertson said.
The SSC endorsed staff’s recommendation to endorse the MISO RDT as a target area for additional analysis in SPP’s Integrated Transmission Planning (ITP) assessment. The Economic Studies Working Group has already endorsed the recommendation.
Planning staffs from both RTOs will hold a March 10 conference call to review “annual issues,” a precursor to a joint study.
Meanwhile, SPP and AECI are drafting the scope document for a potential CSP, which would use reliability models from the RTO’s 2020 ITP and possibly include economic planning analysis. Their Interregional Planning Stakeholder Advisory Committee plans to meet in March, with the hope of producing a final CSP report in July.
Because AECI is not a transmission owner under SPP’s Tariff, the agreement is necessary to outline project specifics and define cost allocation for AECI’s work. FERC’s approval would allow SPP to allocate funds compensating AECI for its work.
Once these steps are finalized, SPP is expected to put the project out for bids. The 2019 ITP assessment identified the project’s need date as Jan. 1, 2026.
M2M Settlements Reach $70M
Another month of multimillion market-to-market (M2M) settlements has pushed MISO’s tab with SPP past the $70 million mark.
SPP-MISO market-to-market settlements | SPP
Temporary and permanent flowgates on the RTOs’ seam were binding for 1,008 hours during December. That resulted in a $2.85 million settlement in SPP’s favor, pushing the overall total to $70.96 million since March 2015.
Under the M2M process, the RTO with the greater economic dispatch addresses market flows.
The Michigan Public Service Commission last week told DTE Electric to extensively revise its 15-year integrated resource plan, finding the utility didn’t adequately factor in the benefits of renewable energy.
The decision, which was neither a rejection nor approval, means DTE must go “back to the drawing board,” the state commission said Thursday. It gave the utility until March 21 to submit a revised IRP (U-20471).
Administrative Law Judge Sally Wallace in late December ruled against DTE’s IRP, saying the utility used outdated information in its modeling that produced results that minimized the advantages of renewable energy and energy efficiency. She also said the plan failed to include competitive bidding for renewable generation to fill capacity needs and leaned too much on natural gas-fired generation. In addition to the $1 billion, 1,150-MW gas-fired Blue Water Energy Center under construction, DTE proposed multiple gas-fired plants rated about 400 MW, 693 MW of wind generation, 11 MW of solar with on-site storage and 859 MW in demand response programs by 2024. (See DTE IRP Draws Fire from Renewable Proponents.)
The commission did not have to follow the judge’s recommendation in its final decision. However, Wallace had said DTE should adjust the plan even if the Michigan PSC decided to approve it.
DTE’s Belle River power plant | DTE Energy
But the trio of regulators largely agreed with the judge’s decision, saying the IRP should contain plans for a request for proposals for new renewable resources. The PSC also initiated two new proceedings in the order, including an April 1 deadline for DTE to update its renewable energy plan and a Nov. 13 deadline to file an application for review of its compliance with the federal Public Utility Regulatory Policies Act.
The PSC also required that DTE reach 1.75% energy savings in 2020 and 2% in 2021, the same targets the commission set for Consumers Energy. Michigan’s statutory minimum is 1% per year; DTE had proposed it satisfy a 1.65% savings in 2020 and 1.75% in 2021.
“The commission acknowledges DTE’s focus in the near term on ways to increase programs to cut energy waste, but we’re recommending that the utility do more to tap into this cost-effective resource,” PSC Chairman Sally Talberg said.
The commission said the plan’s failure to use current data and study renewable alternatives painted an incomplete picture.
“These issues inhibited the commission from assessing the full range of alternatives such as utility- and third-party-owned wind and solar projects,” the PSC said in a statement. In the order, it said there were “significant deficiencies” in DTE’s record, “including a starting point that included a range of nonapproved and nonoptimized resources and the failure to issue a request for proposals for supply-side resource additions.” The commission said it would be best for DTE to remove all the supply-side resource additions it proposed to start fresh.
It also said DTE’s proposal to hold off on full retirement of the coal-fired Belle River power plant near the Canadian border until 2030 was “inadequately justified because an analysis of avoiding new environmental upgrade costs was not considered.”
The PSC agreed with the criticism that DTE’s modeling software Strategist is outdated and no longer supported by its developer ABB Group. It ordered the utility to schedule a technical conference within three months to discuss alternative modeling software with “interested stakeholders.”
The commission didn’t mince words about the stakes for the utility. “Should DTE Electric fail to file a revised IRP that substantially adopts the recommended changes, the commission will be left with little alternative but to deny the IRP,” it said.
It said it accepted thousands of public comments since the plan was filed last March, the “vast majority” urging it to reject the IRP and direct DTE to increase its renewable fleet. Michigan’s reliance on coal has fallen dramatically, from more than 65% of the state’s generation fleet in 2007 to more than 40% in 2017.
“We appreciate the unprecedented amount of public participation generated by the interest in this case, a clear indication that Michiganders are becoming more engaged in helping to shape Michigan’s energy future,” Talberg said.
Michigan generation mix 2007-2017 | Michigan PSC
In a statement, DTE said it was evaluating the recommendations to prepare for a response filing. The company said the IRP “reflects our long-term goals and plans to be a leader in providing cleaner energy to our customers.”
“Since 2009, DTE has been the largest investor in renewables in Michigan, driving $3 billion in solar and wind energy infrastructure and investments. Over the next decade, we will triple our renewable energy assets,” the company added.
DTE had defended its plan in January, calling it the “most reasonable and prudent means” of meeting its energy and capacity needs. The utility repeated claims that it will not have a capacity need to be filled by small qualifying facilities under PURPA for at least the next five years and no planning-level need for additional capacity for at least the next decade. After the Belle River units retire in 2029 and 2030, DTE said it would begin to experience a 585-MW capacity shortfall. Until then, there’s no “persistent capacity need,” the company said.
The Union of Concerned Scientists had been particularly vocal, dogging DTE throughout the process for its reliance on traditional resources and on self-scheduled coal generation.
“So much of the resource plan was ‘hardcoded’ that DTE actually prevented the model from selecting resources that would otherwise provide real economic value to DTE’s customers,” UCS Senior Energy Analyst Joseph Daniel said last year.
A day after the PSC’s decision, Daniel said state regulators cut a “Gordian knot” by “neither approving nor rejecting the IRP but recommending major modification in such a way that is sending DTE back to the drawing board.” He characterized the order as a “Midwestern rejection.”
SACRAMENTO, Calif. — In a controversial decision, the California Energy Commission on Thursday allowed the Sacramento Municipal Utility District to sell solar power to homebuilders and homeowners as an alternative to the rooftop solar panels required on all new homes built in the state after Jan. 1.
The commission adopted the cutting-edge regulations requiring rooftop solar last year but provided that “a community-shared solar electric generation system” could substitute for rooftop solar in new subdivisions. SMUD was the first utility to apply for permission to build community solar under its Neighborhood SolarShares Program last fall.
The commissioners unanimously approved SMUD’s request after a three-hour hearing, during which about 75 speakers addressed them in a hot, crowded hearing room.
Opponents argued that a decision in favor of SMUD would open the door for public utilities, community choice aggregators and eventually investor-owned utilities such as Pacific Gas and Electric to sell solar power to new subdivisions instead of each house or neighborhood having its own solar panels.
“This proposal will significantly undermine rooftop solar and storage in the SMUD territory, and it will set a precedent and a blueprint for other utilities, particularly the IOUs, to do the same,” State Sen. Scott Wiener (D), a PG&E critic, told commissioners. “Because we know that when it comes to PG&E and the other investor-owned utilities … there is no attack on rooftop solar and storage that they will not engage in because they want it to go away, and they see it as competition.”
Wiener said he regretted having to oppose SMUD, which broke away from PG&E more than 70 years ago — as San Francisco, which he represents, wants to do now — and has been a statewide leader in renewable energy.
Steven Lins, director of government affairs at SMUD, countered, “We’re focused on the big picture here, and for us that’s net-zero by 2040. That’s an audacious, aggressive goal, and we’re going to need every tool in the toolbox to get there.
“Neighborhood SolarShares is just one of many strategies that we have for reaching that goal,” he said. “It meets all the requirements. It’s just another path or option for compliance. It creates a choice for builders and buyers. Without Neighborhood SolarShares, there’s quite simply no other choice but rooftop, and that’s not what was intended in the regulations.”
Homebuilders, utility lobbyists and numerous SMUD employees spoke in favor of the community solar proposal. Not all new home buyers want rooftop solar panels, which can increase the purchase price of a house by thousands of dollars and require regular maintenance, they contended. Under SMUD’s proposal, homebuyers would have the choice of purchasing rooftop solar from builders as an add-on option or buying into the community solar program.
“Fundamental to the Energy Commission’s 2020 standards is choice,” said Frank Harris, manager of energy regulatory policy with the California Municipal Utilities Association. “In establishing the eligibility of a community solar option, the Energy Commission recognized that homeowners should have these options. The community solar program can provide a more efficient way to increase solar and maintain choice for homeowners for whom rooftop may not be the best way for introducing solar.”
Environmentalists and solar industry representatives backed Wiener’s views, saying the SMUD plan would harm the movement toward rooftop solar and distributed energy resources.
“The proponents are trying to frame this as a solar-versus-solar decision, which I would imagine would be a hard choice for any and most environmentalists to make,” said Bernadette Del Chiaro, executive director of the California Solar & Storage Association.
“This is not solar versus solar,” she said. “This is the smart buildings of the future versus the dumb buildings of the past. The Energy Commission hoped for innovative community solar projects to come out of the alternative compliance option. All you’re getting today is a very commonplace utility-scale project, the likes of which the [renewable portfolio standard] will already support and bring to the fore.”
Commission staff recommended approval after SMUD agreed to make changes to its Neighborhood SolarShares proposal.
CEC Executive Director Drew Bohan said SMUD had agreed to build new solar farms within its service territory of less than 20 MW each to serve its community solar program. The utility’s initial plan could have imported power from large arrays hundreds of miles away, he said.
Controversy arose because California was the first state in the nation, starting seven weeks ago, to require rooftop solar panels on new residential construction, and opponents believed SMUD’s plan compromised that landmark achievement, Bohan said. (See Calif. Code Change Would Mandate Rooftop Solar.)
Commissioner Andrew McAllister, who oversaw the vetting of SMUD’s plan, said California must continue eliminating greenhouse gases and fossil fuels under Senate Bill 100, Assembly Bill 32 and other historic measures. The electrification of transportation and buildings is key to those efforts, and rooftop solar panels and community solar arrays should both play a role, he said.
“Building decarbonization is a huge topic. It’s a huge project for the state, certainly for the CEC, and it’s bigger than today’s discussion, I would argue,” McAllister said. “This is but one piece of that.”
He called for others to bring innovative proposals to the commission for consideration.
“We need to tend the fields of California’s diverse clean energy landscape so that all its many flowers can continue to bloom,” McAllister said.
WASHINGTON — FERC Commissioners Bernard McNamee and Richard Glick on Thursday voted not to act on a proposed LNG export facility, resulting in the rare surprise at what are usually tightly scripted monthly open meetings (CP17-494, CP17-495).
The commission was prepared to approve Calgary-based Pembina Pipeline’s application for its Jordan Cove LNG export terminal and accompanying Pacific Connector pipeline in Oregon as part of its consent agenda. The project was listed as being approved in a packet summarizing the actions the commission took as part of the meeting’s agenda.
But during his opening remarks, McNamee announced that he would be voting “nay” on the project after he said the state’s Department of Land Conservation and Development (DLCD) “provided a letter, apparently, to the applicant regarding its permits. I want to see what the state of Oregon said, and I need that information to inform my decision about whether I’m going to ultimately vote for or against” the project.
The Oregon DLCD had notified Pembina on Wednesday that it had “determined that the coastal adverse effects from the project will be significant and undermine the vision set forth by the [Oregon Coastal Management Program] and its enforceable policies.” The department cited the federal Coastal Zone Management Act (CZMA), and the regulations implementing the law, in asserting that because it has objected, neither FERC nor the U.S. Army Corps of Engineers could approve the project unless its objection is overridden by U.S. Secretary of Commerce Wilbur Ross.
A rendering of Jordan Cove LNG export terminal, focusing on the processing facility and marine slip from the northwest | Jordan Cove LNG
As required by the CZMA, the DLCD notified both FERC and the corps of its objection, but McNamee told reporters after the meeting he was unaware of what exactly the department had done. According to FERC’s eLibrary, the letter was filed with the commission on Wednesday but not actually published until the day of the meeting.
“All I know is that I saw in the news that Oregon did something on this and supposedly denied certain permits,” he told reporters. “I don’t know the details, and that’s why I want to know what the details are so I can make a reasonable decision.”
Chairman Neil Chatterjee told reporters after the meeting that McNamee informed him of his decision “just prior to the meeting.” Chatterjee had placed the project on the consent agenda in an effort to comply with the directives of the Fixing America’s Surface Transportation Act’s Title 41 (FAST-41), which is intended to improve the coordination between federal agencies in issuing infrastructure permits to speed their construction.
Glick, however, was apparently uninformed of the decision, as he issued a scathing dissent in his opening comments as if the project were going to go through. As the newest commissioner, McNamee is last in the order of who speaks during opening remarks and staff presentations.
Glick said that in addition to his usual objection to FERC not considering the impact of natural gas projects’ greenhouse gas emissions on climate change, the commission was also disregarding an Oregon law charging the state with reducing its carbon dioxide emissions to 14 million metric tons/year by 2050. According to Glick, the project would emit 2 million metric tons of CO2-equivalent per year.
“This is significant. This is going to make it really tough for Oregon to meet its standards here,” Glick said.
The commission ultimately voted 2-1 not to act on the application at the meeting, meaning the project is still pending before it, said Deputy General Counsel David Morenoff, invited by Chatterjee at his press conference to explain to reporters the procedure.
Prior to the vote, as commission Secretary Kimberly Bose read off the list of agenda items, Glick could be seen conferring with his staff and General Counsel James Danly before he joined McNamee in voting “nay” on the Jordan Cove agenda item. Normally, commissioners vote “aye” on the consent agenda after noting their individual dissents and concurrences on specific items.
McNamee said in a statement after the meeting that he voted against the project without prejudice, meaning he did not vote on the merits of the application. But Glick told reporters after the meeting that he was concerned that he could be deemed to have prejudged the matter because of his comments before the vote — though he noted that would mean he would have to recuse himself from the proceeding, leaving the commission without a quorum to act on it. He said he would not have said anything had he known what McNamee was going to do.
The commission could vote on the project again as soon as McNamee is ready, Chatterjee said. McNamee said he expected to be able to vote on it this week.
The Jordan Cove export terminal would be in Coos County, on the southwestern coast of Oregon. It would produce 7.8 million metric tons of LNG per year, according to FERC. The Pacific Connector pipeline would run 229 miles, transporting 1.2 million dekatherms/day of gas to the terminal from a trading hub near the city of Malin, Ore., on the border of California. The project’s website lists “proximity to active Asian markets” as one of its “essential characteristics for an optimal export facility.”
Glick ‘Disappointed’ and ‘Saddened’ by Dissents
Glick issued 14 dissents at the meeting, saying he was “very disappointed that we have gotten to this place, and I’m saddened about what that says about this agency.”
“This is an agency that used to be known for nonpartisanship and compromise, but … I still can’t vote in good conscience for orders that violate the law and come nowhere close to reasoned decision-making.”
Speaking about Jordan Cove, he listed several different impacts unrelated to emissions that he said the commission failed to adequately consider and mitigate.
“I think in this order, we’re actually being honest” about whether the commission weighs the benefits of a project against the adverse impacts in determining if it’s in the public interest, Glick said. “We say, ‘We don’t really do that. We just look at the adverse impacts on landowners, and we weigh that against the economic benefits of the project, and then later on, in the order, we’ll talk about the environmental impacts, but we really don’t include the environmental impacts in our decision-making process.’ Something’s really rotten with that. … I think that’s why the commission has really earned its reputation as being a rubber stamp for these types of pipeline and LNG projects.”
Glick noted that one of the orders he dissented on denied reconsideration of staff giving Enbridge a two-year extension to complete construction of its Atlantic Bridge, a project to expand its Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems (CP16-9). Staff approved the extension Dec. 26, 2018 — the same day it was requested, only 34 minutes after it was published on eLibrary.
“I just don’t understand why … we’ve delegated this [function] to staff,” Glick said.
Glick gave his colleagues credit for establishing a new procedure for requests for extension of time to complete construction going forward. In the order, the commission directed the Office of the Secretary and Office of Energy Projects to notice all such requests within seven calendar days of receipt and establish a 15-calendar-day intervention and comment period deadline.
“But that doesn’t eliminate the injustice that occurred in this case,” Glick said. “I think at the very least we could have granted rehearing and reconsidered” Enbridge’s request.
McNamee acknowledged that the extension approval “doesn’t look good.” He noted that staff were aware of the incoming request and of the project’s ongoing delays because of litigation. But McNamee agreed with Glick that “the public should have more of an opportunity” to comment.
The meeting was interrupted seven times by protesters from environmental group Beyond Extreme Energy, the first such disruption since April 2019. (See Enviro Protesters Scale FERC HQ as Agency OKs More LNG.) The protesters were escorted out of the meeting room by security.
FERC on Thursday largely approved the Order 845 compliance filings for CAISO, NYISO and a handful of utilities, though none of the entities received perfect marks.
The commission said the companies and grid operators mostly adopted its pro forma large generator interconnection procedures but fell short of adopting all language required under Order 845.
The commission directed the two grid operators and five utilities to make additional changes to their filings, focusing on contingent facilities, provisional interconnection service, generators’ technological advancements and surplus interconnection service. The entities have 60 days to address the shortcomings.
In addition to CAISO’s (ER19-1950) and NYISO’s (ER19-1949) partial compliance, FERC found partial compliance from Arizona Public Service (ER19-1939), Cube Yadkin Transmission (ER19-1956), Deseret Power (ER19-1902-001), El Paso Electric (ER19-1953) and LG&E and KU (ER19-1916).
Contingent Facilities
In a familiar line, the commission said the entities’ proposals “lack the requisite transparency … because the proposed tariff revisions do not detail the specific technical screens or analyses and the specific thresholds or criteria that [they] will use as part of its method to identify contingent facilities” — unbuilt interconnection facilities and network upgrades on which the interconnection request’s costs, timing and study findings are dependent.
“Without this information, an interconnection customer will not understand how [they] will evaluate potential contingent facilities to determine their relationship to an individual interconnection request,” FERC said in nearly all the orders, adding that such criteria will ensure that interconnection customers are treated equally.
Revisions related to surplus interconnection service were also a stumbling block for many of the entities.
FERC said CAISO and Deseret failed to include tariff revisions that explicitly require that the transmission provider, original interconnection customer and surplus interconnection service customer file a surplus interconnection service agreement with the commission that outlines the terms and conditions of the service.
The commission directed LG&E/KU to remove a provision that it will not allow surplus interconnection service if the system impact study identifies a need for new interconnection facilities or network upgrades. FERC said while Order 845 does restrict surplus service when network upgrades are needed, it does not “restrict the construction of new interconnection facilities necessary to accommodate surplus interconnection service.”
El Paso Electric must also revise its tariff to explicitly state that surplus interconnection service requests will be processed outside the non-surplus interconnection queue.
Cube Yadkin’s surplus interconnection service provisions also missed the mark, FERC said. The subsidiary of North Carolina hydroelectric company Cube Carolina proposed that “any change made to the existing interconnection service will be treated as a new interconnection request.” FERC said that while Order 845 allows a transmission provider to deny surplus interconnection service if it requires network upgrades, it’s “not for the reasons that Cube Yadkin proposes.”
CAISO
CAISO has the most alterations ahead of it to fully comply with Order 845.
FERC said the ISO’s existing limited operation study — used when an interconnection customer requests service below its full generating facility capacity — missed the aims of Order 845 because the study places restrictions on when a customer may request provisional interconnection service. The limited operation study can only be performed when a transmission owner’s interconnection facilities or network upgrades “are not reasonably expected to be completed” before the generator’s commercial operation date, according to CAISO.
The ISO also must research its Tariff to find evidence that area delivery network upgrades can be cost-capped in the same manner as reliability network upgrades and local delivery network upgrades. FERC said it couldn’t accept some of CAISO’s Tariff language without proof that the practice was already in place. The ISO had said costs for area delivery network upgrades above caps identified in interconnection studies must be financed by the TO.
CAISO also went off-script in its pro forma large generator interconnection procedures when it proposed potential penalties for generators that exceed their level of interconnection service capacity. The commission explicitly decided against penalties for over-generation in Order 845, FERC said, adding that the ISO must make a separate filing to propose over-generation penalties.
Technological Advancements and Provisional Service
FERC also said that CAISO, Cube Yadkin and Deseret failed to mention their requisite 30-day deadline to determine whether a proposed technological advancement to a generation project amounts to a material modification. Additionally, the commission said APS and LG&E/KU didn’t describe studies used to determine whether generators’ technological advancement requests constitute material modifications.
Spotty language around provisional interconnection service was also an impediment to full Order 845 compliance for NYISO and El Paso Electric.
FERC said the ISO’s pro forma large generator interconnection agreement should specify the “frequency with which NYISO will study and update the maximum output of a generating facility” with provisional interconnection service.
The commission also said El Paso Electric’s pledge to update its provisional interconnection studies “whenever changes experienced or projected to occur on the system warrant re-evaluation of the maximum permissible output” was too vague.
Stakeholders will keep a close eye on MISO’s attempt to improve a customer market portal, the RTO’s Steering Committee decided during a Wednesday conference call.
The committee instructed the Market Subcommittee to monitor the RTO’s progress on using more up-to-date information in the Customer Connectivity Environment (CCE).
The nonpublic CCE provides MISO members access to the day-ahead and real-time market user interface, meter data upload applications, and the financial transmission rights and auction revenue rights system.
DTE Energy submitted a complaint on connectivity issues and the state of the data upkeep in the CCE, saying database updates are not being performed regularly.
DTE Manager of Wholesale Market Development Nick Griffin said market participants and MISO software vendors “unnecessarily waste time and resources” during new software testing, “facing extended testing times and elevated costs for software implementations.”
Griffin said during MISO’s rollout of five-minute market settlements in 2018, a “lack of relevant meter data, awards, offers, dispatch instructions, etc.” resulted in a less-than-ideal member testing of the new settlement system.
“We have experienced ongoing production-submission incidents, including unit offers, demand bids and meter data submissions,” DTE said, adding that the problems “reduce confidence in CCE.”
DTE said the problem requires “immediate attention,” especially considering that MISO is refreshing its IT systems as part of its ongoing market platform replacement.
MISO’s Jim Kaminski said staff are aware of the problem and “actively working on the issue.”
“This is quite an issue that we need to take a look at,” SC Chair Tia Elliott said.
SC Mulls Consultant Transparency
The SC may also delve into how forthcoming consultants should be about who they represent during MISO committee meetings.
At the beginning of the year, committee leaders began enforcing a rule that all stakeholders making comments during meetings first identify themselves and who they’re representing before speaking.
The Planning Advisory Committee has reported that some consultants participating in meetings are reluctant to reveal their clients before offering comments or criticisms on MISO presentations.
“There are some individuals in some meetings that are making some rather large requests of MISO. … It would be nice to know who they’re making those requests on behalf of. I think that’s something important to know,” WEC Energy Group’s Chris Plante said.
“I think MISO’s meetings need to be open and fair. And this kind of behavior might not result in fair meetings because of hidden clients … trying to influence the process,” Minnesota Public Utilities Commission staff member Hwikwon Ham said. “I am biased towards the state regulatory sectors and the Minnesota commission. I do not deny this. I want the same of others so I can interpret their opinion in certain matters.”
Elliott said consultants could be bound to nondisclosure agreements. Such consultants also could be representing just one MISO stakeholder or several, she said.
The committee would schedule time at its March 25 meeting during MISO Board Week in New Orleans for a deeper discussion on the issue, Elliott said.
