CARMEL, Ind. — MISO said Tuesday it plans to refile a plan to create external capacity resource zones with FERC by the end of the month.
And the RTO still promises to make zone determinations in time for the 2019/20 planning year capacity auction, officials say.
FERC rejected the proposal earlier this month, saying two aspects of the plan rendered it unreasonable. (See FERC Rejects MISO Plan for External Capacity Zones.) One of the rejected provisions would have allowed external resources bordering two local resource zones to choose in which zone they receive auction credits, while the other would have made holders of evergreen supply contracts eligible for excess auction revenues indefinitely.
During an Aug. 8 Resource Adequacy Subcommittee meeting, MISO attorney Jacob Krouse noted the RTO asked FERC to view the proposal as an integrated package, making the rejection total.
“The commission, under the NRG paradigm, rejected the filing,” Krouse said, referring to the July 2017 D.C. Circuit Court of Appeals ruling that FERC overstepped its authority when it suggested changes to a PJM proposal. MISO stakeholders warned last year that a rejection of the proposal was possible in light of the ruling. (See MISO Members: Court Rebuff May Reduce External Zone Chances.)
But RTO leadership appears undaunted by the rejection, planning to refile the proposal with two revisions Aug. 31.
“MISO believes that with the clear guidance we received from FERC … we are going to be able to refile at the end of the month,” Krouse said. “FERC did not note any concern with the vast majority of MISO’s proposal — just those two parts.”
Under proposed revisions, border resources that have participated in past Planning Resource Auctions will be assigned to the local resource zone in which they previously participated. New external resources that border two or more local resource zones will be assigned to the zone where the unit maintains the greatest electrical connection. MISO said it will measure electrical connectivity through line ratings using a contingency basis.
“MISO is proposing to assign resources to a single [local resource zone] instead of multiple zones,” Krouse explained.
For evergreen supply contracts, MISO now proposes to allow units to collect excess auction revenues only until the end of the original term of the agreement or for two years, whichever is longer. Krouse said the RTO’s filing will also include an option that removes the two-year extension, ending hedge eligibility as soon as the original contract expires. He said MISO intends to let FERC choose the provision it prefers.
Krouse asked for stakeholders to provide reactions to the changes by Aug. 17 and said the RASC will schedule a special Aug. 22 conference call to discuss feedback.
MISO Director of Resource Adequacy Coordination Laura Rauch said the change for border resources will apply only to a small subset of MISO resources.
Some stakeholders said the proposed treatment of evergreen contracts might violate the Mobile-Sierra doctrine, which holds that rates negotiated in a contract should be presumed to be just and reasonable.
“MISO is not changing the terms of the arrangement, so Mobile-Sierra would not apply,” Krouse said, adding that the RTO is not encroaching on the terms of buying and selling power. Rather, such contracts would simply become ineligible for additional hedges from MISO after the original term of the agreement or the proposed two-year transitional period.
“We in no way intend to change or limit the terms of evergreen contracts,” Rauch said. “These contracts were signed without consideration of the capacity construct.”
Others commended the RTO for continuing to pursue external zone designation.
“I really appreciate MISO going in and being aggressive on this. … We’ve been talking about this for half of a decade,” said Coalition of Midwest Power Producers CEO Mark Volpe.
The owners of Salem Harbor Power Station have asked FERC to dismiss allegations that the plant misled ISO-NE with supply offers it could not meet because of insufficient fuel.
FERC’s Office of Enforcement filed an Order to Show Cause on June 18, saying that owners Footprint Power should forfeit more than $2 million in capacity payments Salem Harbor Unit 4 received for a period in June and July 2013 during which the plant’s fuel supply prevented it from operating at its offered capacity. Enforcement also sought $4.2 million in civil penalties. (See Salem Harbor Plant Facing FERC Action.)
Salem Harbor Power Plant | Tetra Tech
In its Aug. 2 response, Footprint’s attorneys said Enforcement “overstates” what ISO-NE expected from the plant, claiming the RTO was aware that NOx emissions limits prevented it from running at full capacity for an entire day. Enforcement also failed to consider the time it took the plant to reach full output from start-up, the attorneys wrote in a 383-page answer that includes audio recordings of conversations between plant and ISO-NE operators and a passage from Joseph Heller’s “Catch-22” (IN18-7).
“The day-ahead offers reflected [the plant’s fuel] limitations. And as the taped phone calls show, the operators repeatedly caveated their estimates about potential availability as uncertain,” they wrote.
Footprint said Enforcement overstated the maximum amount of fuel the plant could burn by more than 82%. Enforcement staff did not interview plant operators and there is no evidence investigators talked with the RTO’s operators about their expectations, Footprint said.
The company also said Enforcement’s calculations understated the amount of fuel the plant had available to burn.
“Enforcement thus offers a conundrum where every option is a violation. If Salem Harbor offers what it considers to be a good estimate of the projected output of Salem Harbor, that is deceptive because the projection is higher than anything empirically proven to be available in advance. If Footprint offers a lower level of output from Salem Harbor, but one that has been empirically proven to be available in advance, that is physical withholding. This is no idle, after-the-fact thought. The principals of Footprint were veterans of the business and regulatory landscape facing New England independent power producers. They understood the regulatory environment in ISO-NE as well as anyone. And they actually were concerned at the time that under-offering Salem Harbor 4 could expose them to withholding claims.”
The filing acknowledges Unit 4 ran low on fuel in July 2013 but noted that the plant was then less than a year from retirement. “Fuel oil had to be bought in large amounts — a barge of oil cost over $5 million in the summer of 2013. And given that the plant historically ran very infrequently, much of that money might end up wasted.” Unit 4 retired less than a year after the period in question, and it and its fuel tank have since been demolished.
Footprint said Enforcement is attempting to penalize it for running low on fuel because the plant was not hit with ISO-NE’s shortage-event penalties. “If the commission wants to create greater incentives to store fuel oil on site, it obviously can do that prospectively by changing the definition of shortage events in the ISO-NE Tariff so that they occur more frequently. The commission in fact approved just such a change in late 2013. But the commission cannot lawfully change the Tariff to make shortage events more frequent looking backwards. … Viewing things from a broader perspective, the Pay-for-Performance capacity model is not going to work as intended if Enforcement gets to pile on its own chosen sanctions, above and beyond shortage-event penalties, whenever it thinks alleged performance limitations somehow have not already been sufficiently punished.”
Footprint also said the case should be dismissed based on the five-year statute of limitations. It disagreed with Enforcement’s prior claims that the issuance of a show cause order within five years is sufficient.
It requested a meeting with the commissioners and senior staff to discuss its defense, “with or without Enforcement present.”
California’s Public Utilities Commission has increasingly focused on wildfire prevention as electric utilities have been blamed for a series of devastating blazes in recent years, the commission’s president told state lawmakers Tuesday.
CPUC President Michael Picker said the commission’s role had shifted significantly from economic regulation to fire safety during years of high temperatures and low humidity “that result in intense fires with 145-mph winds.”
He and others called such conditions the “new normal” in California.
Picker made his comments before a joint committee of state senators and assembly members tasked with ironing out differences in SB 901, which deals with climate change, wildfire prevention and the legal liability of the state’s three investor-owned utilities: Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.
Passed by the State Senate in June, the bill would require a utility’s wildfire mitigation plan to describe what factors it will consider when determining whether to de-energize lines in the face of fire danger and include procedures for notifying affected customers. (See Calif. Senate OKs Utility Wildfire Cost Recovery.) The mitigation plans are subject to CPUC approval.
The hearing was one of several called to draft a workable bill before the legislature adjourns its two-year session Aug. 31, when the bill would otherwise die.
The conference committee’s first hearing was held July 25, when one of its co-chairmen, Sen. Bill Dodd (D), said he was primarily concerned with the safety of residents after hundreds in his Napa County district lost their homes, and some were killed, in the catastrophic wine country fires of 2017.
California Department of Forestry and Fire Protection (Cal Fire) probes have blamed 16 of last year’s Northern California fires on “electric power and distribution lines, conductors and the failure of power poles” owned by PG&E.
The nearly 52,000-acre Atlas Fire in Napa, for example, started when a tree limb and a falling tree came into contact with PG&E power lines, Cal Fire said in a June statement. That fire killed six residents and destroyed 783 structures.
PG&E last quarter took a $2.5 billion pre-tax charge for third-party claims related to 14 of the fires.
Wildfires, the Atlas Fire, made for a smokey San Francisco sunrise in October 2017 | Bob Dass via Creative Commons
Opening the July 25 hearing, Dodd said the state needs greater regulation of line maintenance, including vegetation removal, inspection and power shutdowns during extreme weather conditions, “so power lines don’t start fires.”
He placed part of the blame on the CPUC, alleging lax oversight.
“That means better utility planning and greater accountability for those who operate the grid, including checking compliance before a fire,” Dodd said on the dais in July. “That’s an area where the CPUC has done quite poorly regulating utilities and ensuring public safety.”
Testifying at the same hearing, Picker said the loss of life and homes from wildfires had been keeping him up nights, though he hadn’t expected fire-prevention to be a major part of his job.
“I have to say that fires are not something I thought I would deal with when I came to the Public Utilities Commission. But it’s obvious they are becoming a bigger and more dramatic issue here in the state of California.”
The CPUC in December approved more stringent wildfire standards for utilities, creating a “high fire-threat” district where correction of fire hazards is to be prioritized through improved vegetation management and increased wire-to-wire clearances. (See CPUC Targets Wildfires, Multifamily Solar, RMRs.)
The next hearing on SB 901 is scheduled for Aug. 9, when the subject will be the liability of investor-owned utilities for the destruction of private property caused by wildfires.
Nonutility buyers have contracted for more than 3.5 GW of renewable energy thus far in 2018, breaking the annual record of 3.12 GW set in 2015, the Rocky Mountain Institute’s Business Renewables Center (BRC) reported.
The 46 deals so far this year also best the 31 deals totaling 2.89 GW in 2017.
In total, U.S. corporate purchases of renewables have totaled 13.52 GW since 2008, according to the BRC, which says its member companies have been responsible for most nonutility transactions for renewable energy in the country.
| Rocky Mountain Institute
The center says almost 60 companies have participated to date, up from four companies in 2013.
Facebook, which was one of the original four, pushed 2018’s total to the record with its July 18 announcement that it will buy 437 MW of solar power from six projects for its Prineville, Ore., data centers.
Facebook is among 140 companies that pledged to transition to 100% renewables. Other large purchases this year came from AT&T, Walmart, Microsoft and Apple.
“We are bearing witness to unprecedented growth in this market, which is critical to achieving the goal of a clean, prosperous and secure low-carbon economy,” said Jon Creyts, managing director at RMI.
The BRC, which launched in 2015 with about two dozen members, now has 250.
It helps simplify renewable purchases, offering procurement templates, primers and a Market Analysis Platform to identify the most attractive regions for wind or solar projects. BRC’s Marketplace allows corporate buyers to search wind and solar power projects available for off-take and gives developers a way to market their projects and collect information from potential buyers.
BRC’s goal is to facilitate procurement of 60 GW of renewables by 2030.
In addition to providing a way to enhance their green credentials, corporations increasingly see renewables as cost-effective. For example, storage and information management company Iron Mountain signed a 15-year power purchase agreement for wind in 2016 that it says will save it up to $500,000 in power costs annually. (See Cost Trends Favor Renewables Despite Coming Policy Shifts.)
In 2015, corporations passed utilities as the top purchaser of wind power.
MISO’s Energy Storage Task Force is making a bid to broaden its role by seeking the authority to evaluate storage issues in addition to identifying them.
The group moved to revise its charter during a Tuesday conference, but any proposed changes are subject to approval by the Steering Committee at its next meeting.
The task force is currently limited to only identifying storage issues requiring MISO’s attention. It then forwards its findings to the Steering Committee, which assigns the issues to larger stakeholder committees for decisions. (See MISO Storage Task Force Defines Role, Seeks Plan.)
But the group now wants the authority to evaluate “issues or topics that are unique to the integration or challenge the realization of benefits of energy storage,” according to the revised charter. It would “also provide ongoing subject matter expertise to MISO entities regarding storage-related issues.”
Task force Chair John Fernandes said the initial charter may have been too restrictive.
“That was a very unilateral, one-way mission statement,” Fernandes said. “What we’re saying here is that there’s an opportunity for extended dialogue.”
He said it can sometimes feel as if the group encounters “radio silence” after it identifies an issue taken up by a larger stakeholder committee.
Fernandes said the group will reconvene in September to discuss next steps if the Steering Committee refuses to approve the expanded charter.
Some stakeholders said the revised charter might open the door to two stakeholder groups having the same discussions about energy storage, violating the spirit of MISO’s stakeholder process redesign three years ago that sought to reduce duplicative discussions across different RTO forums. (See MISO Takes Stakeholders’ Temperature on Redesign.)
But Fernandes said there are broad storage subjects that warrant further task force discussions even if a specific issue may have been escalated to another MISO group. He cited hybrid storage facilities as an example, noting the interconnection of such plants is currently under discussion within the RTO, but the general business model requires more evaluation.
Fernandes also questioned the efficiency of stakeholder committees creating new task teams to discuss unique storage attributes when the task force could evaluate them.
He added that the task force plans to continue to stay out of developing commercial business models for storage, as recommended by the Steering Committee.
MISO last week laid out how it will tackle changing resource availability and needs in its footprint ahead of the release of a white paper on the issue.
The RTO told stakeholders it will focus on four key areas: resource accreditation, the annual capacity auction, outage scheduling and its own expectations for resource availability.
MISO Executive Director of Market Development Jeff Bladen said the project will aim to determine how the RTO can more efficiently turn committed capacity into available energy in a climate of diminishing reserve margins and growing use of intermittent resources.
“[This] is about making sure we can meet operating needs every hour of every day,” Bladen said during an Aug. 3 Reliability Subcommittee meeting. “This is becoming more critical as we see a narrowing gap between load and resources, which have increased the occurrence of emergency operations throughout the year.”
The four areas entail:
Studying characteristics of different resources to learn how to best incentivize them to create more flexible availability systemwide.
Evaluating the current Planning Resource Auction design. MISO said it will examine how it can best procure adequate resources throughout the planning year and reexamine how it accredits resources.
Ensuring that MISO’s outage process matches expected resource output with resource commitments. Bladen said MISO will look into how it can get more information on outages and the risk of outages, and examine how it can better model the risk in its planning process. The RTO says “a significant number” of unit operators change the start dates of outages within a month of the originally scheduled outage.
Aligning resource expectations and obligations with availability. For this, Bladen said MISO will ask what availability should be expected of resources; whether current emergency operating procedures are adequate; and whether resources provide the RTO enough information on their availability times. Bladen said MISO will focus especially on load-modifying resources, whose performance has been lacking during emergency declarations. (See “LMR Performance in January,” MISO Mulls Additional Emergency Communication.)
MISO’s Steering Committee will assign the issues to various stakeholder groups after next month’s release of a white paper explaining the issues in more detail.
Bladen said he expects MISO and stakeholders will work on implementing recommendations as they develop the project through late 2020.
In response to a question from WPPI Energy economist Valy Goepfrich, Bladen said MISO might be open to altering its loss-of-load study to reflect a departure from planning for a summer peak, but that such a move would not solve the issue entirely because the study and resulting reserve margin is a “blunt instrument.”
Bladen also said he was deliberately not suggesting a rule similar to PJM’s Capacity Performance. While CP may come up as MISO and stakeholders discuss solutions, the RTO instead wants to emphasize incentives so that the “capacity we’re counting on — and has arguably already been paid for by ratepayers — is available to us.”
New Notification System
As it debates how to address changing resource availability, MISO will this month roll out a new notification type to give members more warning of forecasted capacity shortages.
The new capacity advisory, which MISO plans to use when all-in capacity is forecast to be less than 5% above operating needs, is meant to be an intermediary step before declaring a maximum generation alert.
Manager of Unit Commitment and Dispatch Phil Van Schaack said the new advisory is strictly an informational communication and does not carry any operational instructions. However, the new notice does request that unit operators update their data and availability in the MISO system.
Van Schaack said the additional notification would be especially useful for weekends and going into Mondays, when generation assets tend to be more sparsely staffed.
“This is for when we want people to get looking at things when they’re ordinarily not looking at things,” Van Schaack said.
After stakeholders asked for more real-time electronic communication of tight operating conditions, MISO declared a maximum generation alert on a Friday in mid-May for predicted Monday conditions that did not materialize. With hindsight, some stakeholders said declaring the alert may have been overly cautious. (See MISO Mulls Additional Emergency Communication.)
Under the new approach, MISO will send a capacity advisory communication to members when it foresees tight operating conditions in advance.
“Everyone wanted proactive information, but they oppose restrictions or impacts to operations,” Van Schaack said. “The capacity advisory addresses stakeholder requests for transparency of forecasted conditions without impact to operations.”
The Indiana Utility Regulatory Commission’s Dave Johnston asked how the new notification will differ from MISO’s current hot weather alerts.
“The intent is more to say that ‘this is a capacity issue’ and ‘please review some of the data that you’ve submitted.’ I would say there’s some overlap, but for the hot weather alerts, we need about 99 degrees in Little Rock or so,” Van Schaack said.
MISO staff said they would have sent out the capacity advisory a few times this summer had the process been in place.
NYISO’s release of draft carbon pricing recommendations — and its refusal to immediately discuss the report — sparked annoyance and frustration among some stakeholders Monday.
The nine-page draft, released Aug. 1, summarizes discussions to date in New York’s Integrating Public Policy Task Force (IPPTF).
But NYISO staff declined to discuss it at Monday’s IPPTF meeting, which was scheduled for a briefing on the ISO’s “Dynamic Change Case” — its analysis to refine estimates of how carbon prices will impact customer costs.
Before the briefing began, several stakeholders pressed ISO staff to answer questions about the draft recommendations. IPPTF Chair Nicole Bouchez, the ISO’s principal economist, promised to schedule time for the discussion but said it would likely not occur before Aug. 27.
Attorney Kevin Lang, representing New York City, questioned language in the document that suggested the ISO was making decisions on issues that should be subject to a stakeholder vote. “It’s not up to the NYISO to adopt things,” he said.
“The draft is just a draft,” Bouchez responded. “It was based on our best understanding of the discussions and a coherent proposal. We’re definitely looking forward to input on any and all components.”
Jay Brew, attorney for Nucor Steel Auburn, said he also had questions about the recommendations, citing as an example, “basic principles that were applied by NYISO staff” regarding the allocation of carbon residual payments.
“I think the NYISO should be aware of the effect it has on the market — even something with a ‘draft’ recommendation,” added Seth Kaplan of EDP Renewables. “Be aware that you guys are producing turbulence out in the market as you float these things.”
“Nicole, we asked you not to do this. We said that it’s premature to put out recommendations,” interjected Lang. “You rejected that and said, ‘No, we have to do it.’ For the NYISO to now put out a series of draft recommendations and then not schedule anything to discuss them and just have them sitting there is inappropriate.”
“Thank you for your feedback,” Bouchez responded evenly. “We’ll look for continued discussion and get something scheduled.”
The task force is not scheduled to meet Aug. 13, and the Aug. 20 meeting is tentatively earmarked for presentations by two stakeholders, Bouchez said, making Aug. 27 the first time the recommendations could be discussed.
Report Builds on Straw Proposal
NYISO said its report builds on the April 30 straw proposal on a potential design for incorporating the social cost of carbon (SCC) into the ISO’s wholesale markets and subsequent stakeholder discussion.
The ISO proposed implementing the SCC without a transition mechanism and said internal suppliers participating in the wholesale markets will self-report their carbon emissions or their estimated emissions to the ISO weekly, subject to true-ups.
It rejected a proposal by some stakeholders that the ISO estimate emissions and have suppliers report final emissions. “This approach was not adopted because suppliers are better positioned to accurately estimate their emissions than the NYISO,” the report said.
Still under review by the ISO is whether the carbon impact on each component of the locational-based marginal price (LBMP) needs to be determined and how to prevent what the ISO called “double payments” for the same carbon reductions. The ISO cited stakeholder concerns that some resources may receive both state renewable energy credits and the ISO’s carbon charge.
EDP’s Kaplan took issue with the ISO’s statement, saying it “sort of assumes the REC payments are a carbon payment, which a lot of us would say is not true. So simply embedding it as an assertion … before a discussion [with stakeholders] is troubling.”
The ISO also has not decided on how to handle external transactions, saying it “is considering whether the external proxy bus LBMPs should be posted without the carbon effects rather than establishing a settlement mechanism that applies a carbon charge to imports and a credit to exports.”
It also noted the “robust stakeholder discussion” over how carbon charges will be allocated to loads, outlining four proposals without expressing a preference for one.
Questions on Analysis
ISO officials also faced tough questions during the briefing on the Dynamic Change Case.
Lang questioned how the NYISO will adjust the results of the MAPS analysis regarding the assumed location of renewable resources.
“Wind is being sited in particular areas because of cheap land, wide open spaces and good wind,” said Lang. He asked what the NYISO’s basis is for assuming that developers would move projects into other areas, such as Rockland County or New York City, solely because of higher LBMPs.
Bouchez said the ISO is not projecting wind development in the city.
“It is reasonable to assume — and I’ve talked to a number of developers — as to whether or not higher LBMPs in different locations would affect their choice to develop a project or not. And the answer has always been yes, because they’re looking to all the inputs to the project.”
Lang said it appeared the ISO was using a “very ad hoc approach, without any kind of methodology” and asked that NYISO discuss its methodology before performing the analysis.
Bouchez promised to research the issue with the experts working on it and report back. But she could not promise an explanation would come before the analysis is conducted. Officials said the first results from the analysis should be available about Sept. 10.
Mike Mager, representing Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said his client is unlikely to support carbon pricing without more certainty about how the state Public Service Commission will allocate residual payments to customers and between residential and non-residential accounts.
“We’re trying to get comfortable with [the concept of ] carbon pricing,” Mager said. “Are you telling us we’re going to vote on something and have no idea whether the PSC is ever going to let [all of the carbon residuals even] flow back to end-use customers or flow [them] back in an equitable manner? We would automatically oppose that. I think you’re going to get a lot of concern from other parties too. …
“I view it similarly to the whole issue of how is the carbon price set? How is it updated? When is it updated? What’s the method for updating it? These are all huge gaps in the proposal that [are] going to need to be fleshed out before something’s ready to be voted on, in my opinion. Otherwise you’re going to get a lot of votes in opposition due to the extreme uncertainty.”
Bouchez said a vote is unlikely before the second quarter of 2019 and that the ISO will begin its normal stakeholder process once the task force concludes its work.
“So we’re going to, at that point, spend a lot of time talking about exactly what we mean and how do we do this and how do equations for different things work and what does the Tariff look like. So that at that point we’ll be really nailing down a lot of the details but also potentially talking about different options,” she said. “So, I think there’s lots of opportunities to have those detailed discussions.”
NiSource last week reported second-quarter earnings of $23.2 million ($0.07/share), compared to a net loss of $44.4 million ($0.14/share) for the same period a year ago because of a hefty refinancing fee. (See NiSource Blames Debt Refinance Fee for Q2 Loss.)
The Merrillville, Ind.-based parent of Northern Indiana Public Service Co. and Columbia Gas earned $299.3 million ($0.86/share) for the first half of 2018.
Speaking during an Aug. 1 earnings call, CEO Joe Hamrock said the company has taken steps to strengthen the company’s finances in response to federal tax cuts, including offering about 25 million shares ($600 million) of common stock in a private placement and refinancing $760 million in long-term debt through the issuance of $400 million of preferred stock and $350 million of five-year notes.
NIPSCO transmission | NIPSCO
“Due to financial statement impacts and the timing of federal tax reform implementation, our year-over-year consolidated results can be difficult to compare,” CFO Donald Brown said. “However … we are making continued progress on managing our annual operating and maintenance expenses, and we now expect our annual O&M expenses to be down approximately 4% in 2018 versus 2017.”
NiSource also remains on track to invest up to $1.8 billion in regulated utility infrastructure in this year, Hamrock said.
Hamrock said NiSource subsidiary Northern Indiana Public Service Co. placed two major Indiana transmission projects into service during the quarter, including the 100-mile, 345-kV Reynolds-Topeka transmission line and the 70-mile, 765-kV Greentown-Reynolds line. The projects, which cost a combined $600 million, were both part of MISO’s 17-project multi-value portfolio approved in 2011. (See MISO Triennial Review Shows Multi-Value Project Benefits.) Hamrock said the lines will “enhance regionwide system reliability, provide environmental benefits by increasing access to wind and solar energy and improve access to lower-cost electricity for customers.”
NIPSCO has also solicited 90 proposals for replacement capacity through its integrated resource plan, targeted for submission to the Indiana Utility Regulatory Commission by the end of the year.
Hamrock said the company received a “robust response to our request for proposals that should provide diverse options to meet our customers’ electricity needs for years to come.” He added the proposals total more than 20 GW with “several diverse fuel options.”
“The next step is to fully evaluate all of these options to develop the right portfolio of generation to best serve our Indiana electric customers,” he added.
In its last IRP, NIPSCO announced it planned to retire 50% of its coal-fired fleet by 2023. The company retired its 480-MW Bailly Generating Station Units 7 and 8 in northern Indiana on Lake Michigan in May, according to schedule. Both units were more than 50 years old.
VALLEY FORGE, Pa. — FERC wants PJM’s capacity rules to be resolved by Jan. 4 and has dispatched staff to help the RTO and its stakeholders adhere to that timeline.
Three FERC representatives attended Thursday’s special session of the Markets and Reliability Committee on responding to the commission’s June 29 ruling rejecting PJM’s “jump ball” capacity filing.
Office of General Counsel attorney Matthew Estes, one of the three FERC representatives, stressed that they were non-decisional and therefore not speaking to or for the commission. He advised all stakeholders to address the commission directly with their interests by filing comments in the docket.
“We’re happy to give our input, but that’s not going to get to the commission,” he said.
He described the representatives’ role as “historians” who could explain what they understand the current situation to be and to provide insight into what stakeholders might consider proposing because it would be “helpful to the commission to have things they can realistically consider.”
FERC rejected both of PJM’s proposals to revise its capacity market (ER18-1314), partially granted a 2016 complaint led by Calpine (EL16-49) and initiated a Section 206 proceeding for a “paper hearing” on an alternative approach in which the RTO would expand its minimum offer price rule (MOPR) to all subsidized resources (EL18-178). (See FERC Orders PJM Capacity Market Revamp.)
Comments prior to the hearing are due on Aug. 28. FERC said that it hoped to issue a final ruling by Jan. 4, 2019, in time for the 2019 Base Residual Auction.
The size of the task led several stakeholders to file for extensions on the Aug. 28 deadline. But PJM staff said they plan to provide comments by the deadline and still accept input from stakeholders. Thursday’s meeting, along with a follow-up scheduled for Aug. 15, are intended for that purpose.
“That doesn’t leave a whole lot of time for extension. I know people want more time,” Estes said.
PJM plans to file a proposal that would follow FERC’s suggestion of combining an expanded MOPR with a unit-specific fixed resource requirement (FRR). The MOPR would have few exceptions and would include units receiving out-of-market payments, such as state subsidies for nuclear units. Such units could then use the FRR option to be removed from the capacity auction, if they can take with them an “appropriate corresponding quantity of load.”
Four Proposals
PJM solicited comments from stakeholders as part of developing its proposal and was surprised to receive four other proposals among the 19 responses. At Thursday’s meeting, representatives of the four proposals outlined their ideas.
Calpine has advocated for a “strong” MOPR with no exceptions, the company’s Sarah Novosel said, but recognizes that other stakeholders don’t agree.
“We’re ready to work on an accommodation, but we think there’s a better accommodation than FRR,” she said, suggesting an approach like ISO-NE’s Competitive Auctions with Sponsored Resources.
LS Power proposed combining the MOPR with a “resource specific requirement” that would be similar to the FRR but remove load based on where the resource’s generation is “electrically delivered” rather than its physical location. It would subject the load and generation that remains in the auction to increased reliability requirements. Those costs would be borne by the resource electing to leave the auction.
Panda Power Funds offered an alternative to FRR that would identify and mitigate subsidized resources and allow those that don’t clear the auction an opportunity to buy capacity commitments in a second auction phase.
Consultants Rob Gramlich of Grid Strategies and James Wilson of Wilson Energy Economics presented a proposal for the Resource Specific FRR developed for the Sierra Club, Natural Resources Defense Council, D.C. Office of the People’s Counsel and American Council on Renewable Energy. They characterized it as “very close” to PJM’s proposal and said it makes the process “as usable as possible” for states. [Editor’s Note: An earlier version of this story incorrectly quoted the consultants as favoring an expanded MOPR.]
Joe Bowring, PJM’s Independent Market Monitor, warned that the unit-specific FRR results in price suppression if the
subsidized resource would not clear in the auction without FRR — and could affect clearing prices either up or down if it would have cleared.
Estes confirmed that FERC had not required an FRR to be part of any proposal, nor has it ruled on whether self-supply units should get a MOPR exemption. He advised stakeholders to file their requests along with substantiation that goes beyond assuming the way things have been traditionally should continue because “FERC found the way it’s always been to not be just and reasonable.”
PJM’s Jen Tribulski agreed with Estes’ analysis on FERC’s FRR proposal.
“We don’t view it as a strict mandate, but we do view it as the commission looks at it as a viable option to accommodate state actions,” she said.
Calpine also agreed.
“I think it’s clear that we at Calpine do not believe that the partial FRR was a mandate, just a suggestion. We think they’re open to other alternatives as well,” Novosel said.
BOSTON — This year’s legislative sessions in New England produced clean energy developments ranging from Connecticut’s “most important energy bill” in seven years, to Massachusetts taking “baby steps,” to Rhode Island taking what might turn out to be a “regrettable pause.”
Vermont even passed a bill requiring the installation of electric aircraft charging stations at state-owned airports.
One unresolved issue among most of the six states in the region relates to the siting of renewable energy resources, Northeast Clean Energy Council (NECEC) Executive Vice President Janet Gail Besser said Thursday at the group’s annual legislative roundup, hosted by Boston-based law firm Pierce Atwood.
“Should there be different siting standards for renewables than for other kinds of development?” Besser said before the group’s state coordinators provided an overview of new clean energy legislation in New England. “How do you preserve farmland and forestland and how do you have compatible uses of land?”
Connecticut Expands RPS, GHG Targets
Mike Martone, of law firm Murtha Cullina, said one new Connecticut law, SB9, “was hotly contested throughout the year… [and] was the most important bill this session and arguably the most important clean energy bill since Public Act 11-80 was enacted seven years ago,” which established the state’s Department of Energy and Environmental Protection.
The law revoked net metering guarantees that ensure rooftop solar owners earn retail prices for their excess electricity. (See Connecticut Energy Bill Draws Mixed Reviews.) It calls for the state’s Public Utilities Regulatory Authority to set up a docket by Sept. 1 “to select the netting time between real time, one day or a fraction of a day, which is still going to be very problematic,” Martone said.
But it also increased the state’s renewable portfolio standard to 40% by 2030; extended the low- and zero-emission renewable energy credits program an additional year; and established a new tariff-based program for low- and zero-emissions projects, shared clean energy, and virtual net metering. The legislature also restored $10 million in energy efficiency funding to the 2019 state budget, Martone said.
Another new law (Public Act 18-82) establishes an interim target of reducing greenhouse gas emissions to 45% below 2001 levels by 2030, and updates Connecticut’s Comprehensive Energy Strategy, the state’s triennial plan to meet its energy needs, to include planning for climate change and a strategy to meet the new GHG target.
It also established the Connecticut Council on Climate Change, which is charged with coordinating the efforts on emissions among businesses, state and municipal agencies, and nonprofits.
Massachusetts on Track
Massachusetts concluded its two-year legislative session July 31 by passing a bill (H. 4756) to increase renewable energy usage and reduce high-cost peak hours. The bill includes a clean-peak standard, the first in the nation to promote the use of renewable resources to shave peak loads.
The bill, one of 175 energy-related ones considered in the session, also allows the Department of Energy Resources to solicit an additional 1,600 MW of offshore wind by 2035 and increases the state’s energy storage target to 1,000 MW by 2025.
“I don’t want to say we had a good two years, but we had a great 48 hours at the end of the session,” said Dan Bosley of NECEC. “A lot of people were disappointed, but the more we looked, the more we realized we got a lot of our initiatives in this bill.”
The legislation mandates that clean energy sources supply an additional 2% of the state’s electricity each year, dropping to 1% in 2030 in order to “bring the business groups on,” he said.
While the bill did not raise the cap on solar net metering, it did modify language related to the monthly minimum reliability contribution charge, which will compel everybody to refile with state regulators, Bosley said.
NECEC President Peter Rothstein called the bill “a step in the right direction,” but the state’s Sierra Club director, Emily Norton, said it represented “baby steps on clean energy legislation when what is needed are giant strides.”
The environmental bond bill (H.4599) authorized $211 million to be spent on climate programs and state hazard mitigation, Bosley said. (See New England Women Talk Climate Change, Resilience.) That includes $10 million for a clearing house “to monitor, project and collate information so that we can do things that we want in an intelligent way,” Bosley said.
The bills have not been signed into law yet.
Rhode Island Pauses
Rhode Island had two landmark years for clean energy legislation in 2016 and 2017, and an exciting time this year in procuring 400 MW of offshore wind, but it was “not a banner year for legislation,” NECEC Policy Analyst Jamie Dickerson said.
“I think it’s going to shape up as a regrettable pause in what has otherwise been a tremendous three or four years of strong and steady growth,” he said.
Legislation that failed to pass would have tweaked the state’s renewable energy growth program to allow additional megawatts to be allocated to the residential solar, Dickerson said. In the 2017 program year, 6.5 MW were allocated for residential solar, and that capacity sold out in six months.
Other bills on the siting of renewables, harmful forest siting, capping energy efficiency program investments, and carbon pricing were either not taken up before the end of the session or referred to committee.
A substitute version of one bill, providing for independent review and verification of ongoing energy efficiency programs, was passed and signed by the governor, Dickerson said.
Northern New England
Kate Epsen, executive director of the New Hampshire Sustainable Energy Association, provided an overview of the conclusion of the Granite State’s second year of a biennium session.
SB 321, signed into law in June, removed the requirement that members of a net-metering group use the same default supplier as the group’s host, allowing residents to use both net metering and retail choice. “This is really helpful because it allows a lot of those larger end users who clearly shifted to competitive supply years ago, and don’t want to go back, to also engage in rural renewable energy projects through net metering,” Epsen said.
On the other hand, Gov. Chris Sununu vetoed SB 446, which would have raised the net metering cap to 5 MW from 1 MW and set the price at the default rate, which changes every six months. The Senate already has the two-thirds majority needed to override the veto on Sept. 13, “Override Day,” she said.
“The veto was unfortunate, for the Republican governor had a lot of cover, with many Republicans favoring it, so this veto happened for about five people in one company,” Epsen said. “That’s how local some of these relationships can get.”
In Maine, Gov. Paul LePage in his two terms since 2010 has vetoed more bills, 642, than all other Maine governors in the past century combined, said Melissa Winne, executive director of the Environmental & Energy Technology Council of Maine.
All energy-related bills, save one, either died in committee, died in special session or were vetoed. The exception was a bill, enacted without the governor’s signature, that extends Maine’s participation in the Regional Greenhouse Gas Initiative through 2030.
Olivia Campbell Andersen of Renewable Energy Vermont highlighted H.676, a law eliminating state fees for rooftop solar and removing mandatory setbacks for solar parking lot canopies, as well as a law that maintained net metering for up to 500 kW.
“Utilities have made it very clear that they would like to have net metering only go up to 150 kW,” Andersen said.
