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.
NRG Energy reported net income of $24 million ($0.23/share) in the second quarter, compared with a $16 million loss (-$1.98/share) a year earlier. Earnings from continuing operations were $121 million in the quarter, up 22% from the same period last year.
The company credited cost-cutting measures, the sale of assets and the consummation of a settlement with its spun-off GenOn Energy business. “Our portfolio is demonstrating once again the value of integration between retail and generation during the volatile summer months, particularly in Texas,” CEO Mauricio Gutierrez said during an earnings call Thursday.
The company has realized $225 million in cost savings through the second quarter of 2018 and is on track to close up to $3 billion in asset sales this year.
Record Peak in Texas
Gutierrez noted that the supply/demand balance in ERCOT is the tightest it has been in many years because of steady load growth and the retirement of nearly 5 GW of generation in the past 12 months.
| NRG
“This market tightening led to an increased probability of scarcity conditions this summer, which was reflected in higher forward prices,” he said. “So far, demand has not disappointed, setting a new record peak of over 73 GW in July. However, this record load was met with equally impressive reliability across the grid, which tempers real-time pricing.” (See ERCOT Sets New All-time Demand Record; Prices Spike.)
“In other words, it took nearly perfect systemwide reliability to meet the summer peak demand,” he said.
“These conditions create an opportunity for both sides of our business and highlight the longer-term value of our integrated approach.”
Big East
Results from the PJM capacity auction this past May reflected fewer new builds and significant amounts of uncleared capacity, signaling more disciplined development and bidding behavior, Gutierrez said. On a “same-store” basis, NRG cleared more megawatts at higher prices than the previous auction, he added.
| NRG
Going forward, the company will seek assets in “premium locations,” Gutierrez said, noting that NRG now has 85% of its PJM fleet in the ComEd zone, which separated to clear at $196/MW-day.
“Throughout the East, we are encouraged by the multiple regulatory avenues for market reform that could benefit both our generation and retail businesses,” Gutierrez said.
NRG increased its bet on retail sales in June, when it completed its acquisition of XOOM Energy, an electricity and natural gas provider with more than 300,000 customers primarily in the East, for $208 million. The company expects XOOM to add $11 million of net income and $45 million of adjusted EBITDA annually.
Faster Asset Sales
NRG Headquarters in Princeton, NJ. | NRG
The company also highlighted its progress in unwinding its relationship with GenOn, the product of the merger of RRI Energy and Mirant, which NRG purchased in 2012 for $1.7 billion. GenOn filed for Chapter 11 bankruptcy in 2017. NRG executed a settlement in July that included releases from GenOn and will terminate shared services on Aug. 15. Other than certain pension and post-retirement obligations and certain claims for REMA, an indirect GenOn subsidiary, the settlement provides NRG full releases from GenOn and its debtor and non-debtor subsidiaries.
GenOn is planning to exit bankruptcy on Oct. 1.
NRG closed on the sale of Boston Energy Trading and Marketing, as well as on its Spanish Town asset, a solar facility in the Virgin Islands, while reaching an agreement to sell its interest in two additional assets, the Keystone and Conemaugh coal-fired power plants in Pennsylvania.
“We actually had anticipated selling these assets in 2019, but we were able to accelerate this timeline and execute on the opportunity to monetize these assets ahead of schedule,” Gutierrez said.
The sale of NRG Yield has received all necessary regulatory approvals and should close in the third quarter, he said. The company’s sale of its South Central portfolio — 3,555 MW of gas- and coal-fired generation on the Gulf Coast — is also expected to close in the second half of this year.
Consolidated Edison earned $188 million ($0.60/share) in the second quarter, a 7% increase from $175 million ($0.57/share) in the same period last year.
The company reported about $2.7 billion in revenue for the quarter, a 2% increase over last year.
Adjusted earnings, which exclude the effects of a gain on the sale of a solar electric production project in 2017 and the net mark-to-market effects of Con Edison Clean Energy Businesses, were $189 million ($0.61/share) compared with $178 million ($0.58/share) in 2017.
Following a proceeding investigating a New York City subway power outage (Case 17-E-0428), the state Public Service Commission last year required Con Ed’s primary utility subsidiary, Consolidated Edison Company of New York (CECONY), to upgrade electrical equipment that serves the system. Costs related to that matter totaled $180 million, including $30 million in capital and operating and maintenance costs reflected in the company’s electric rate plan and $150 million deferred as a regulatory asset.
Following a settlement with state regulators over a New York City subway outage, CECONY has spent $180 million upgrading equipment serving the system. | Joren via Unsplash
Through June 30, CECONY’s costs related to March 2018 storms amounted to $126 million, while fellow subsidiaries Orange and Rockland Utilities (O&R) and Rockland Electric Co. had storm-related costs of $48 million and $18 million, respectively. Recovery of those costs is subject to review by the PSC and the New Jersey Board of Public Utilities. Con Ed and CECONY are unable to estimate the amount or range of their possible loss in connection with the storms, they said.
(a) average rate base for 12 months ended 6.30.2018 | ConEd
In May 2018, PSC staff recommended a $10.6 million increase in O&R’s electric rates and a $6.7 million decrease in O&R’s gas rates, both reflecting an 8.6% return on equity. In June 2018, O&R filed an update to its requested rate increases, changing its request to a $30.4 million increase for electric and a $0.5 million decrease for gas, seeking a 9.75% ROE.
Con Ed reported its Clean Energy Businesses having 1,383 MW of renewable energy production projects in service and 218 MW under construction.
OMAHA, Neb. — SPP’s Board of Directors last week approved a Tariff change requiring non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs), prompting a discussion on the value virtual trades offer the markets.
Staff said the Tariff change (MWG-RR272), which will require resources to reduce their output when instructed, will improve SPP’s ability to manage congestion and lead to an increased convergence between day-ahead and real-time prices.
However, several directors wondered aloud whether the measure would lead to unintended consequences. Virtual transactions are driven by market inefficiencies, so the more efficient the market, the less value in virtuals.
Director Bruce Scherr noted that staff cited as one benefit an expected reduction in profits for virtual traders.
“I never really understand whether we are encouraging or discouraging the participation of virtuals in our market,” he said during the board’s July 31 meeting with the Members Committee. “I think we flip and we flop on that. It’s never been clear to me whether we find virtual participation a positive or a negative.”
Fellow Director Graham Edwards pointed out virtuals are a small part of SPP’s market and asked, “If we start driving the virtuals out, is there a negative?”
SPP’s Market Monitoring Unit said in its most recent market assessment that virtual transactions as a percent of load increased to 17% this spring, compared to 10% in 2017.
“There are times when virtuals can be a help, there are times when virtuals can be parasitic,” responded Keith Collins, the MMU’s executive director. “In this scenario, if they are benefiting as a result of something that is a result of modeling inconsistency, are they really adding a benefit or value to the market? Yes, they are making money, but they’re making money on consistent modeling differences.”
Collins said virtuals can make the day-ahead market more efficient when load is under-scheduled.
“The value here [with RR272] is switching from virtuals to other resources and reducing uplift payments everyone around this table is paying,” he said.
Resources must convert by Jan. 1, 2021, or the 10-year anniversary of its original commercial operation date, whichever is later. Qualified facilities under the Public Utility Regulatory Policies Act and run-of-river hydro projects incapable of following dispatch instructions are exempt.
Staff’s analysis of RR272’s economic effects found the change would improve congestion management and convergence of real-time and day-ahead prices. The analysis projects about $15,000 in additional monthly real-time energy payments to converted NDVERs and about $20,000 in additional revenue to other resources.
“The more dispatchable resources we have, the easier it is to solve congestion,” said Gary Cate, SPP’s manager of market design. “NDVERs are generally located in areas where they are one of the few that are dispatchable. Opening them up allowed us to get rid of those breaches … by a fairly significant amount.”
Liberty Utilities, Omaha Public Power District (OPPD) and Walmart opposed the measure, which also received a pair of abstentions.
“This is an after-the-fact rulemaking scenario, where we’re required to upgrade equipment on older facilities,” said OPPD’s Joe Lang. “We’re concerned about the oppressive nature of this on wind power and setting precedent for other generation. The EPA has new-source-review requirements that properly limit the applicability of new rules on older facilities that give us concerns about walking down this path.”
The Wind Coalition’s Steve Gaw, who didn’t have a vote, said his group is “very supportive” of market efficiency, but he also expressed his concerns about RR272’s wording. He pointed to ambiguity as to when the conversions should take place for non-SPP generator interconnections and the excessive burden it places on the conversion of certain older wind farms.
“There are two issues of substance,” Gaw said. “One, whether or not SPP should be directly stating the conversion costs should be on the interconnection customer, as is stated in the new language. And two, the lack of any kind of exception for resources that have a substantial cost to convert.”
In written comments, the coalition said the conversion of fixed-speed (Type 1) and variable-slip (Type 2) turbines “can amount to millions” in capital expenditures.
SPP, MISO Resolving Jan. 17 Issues
CEO Nick Brown told stakeholders during his president’s report that SPP has reached an agreement with MISO on “specific operating procedures pursuant to our operating agreement” that arose during a Jan. 17 severe-weather event staff refer to as “The Big Chill.”
Colder-than-normal weather and generation shortfalls in MISO South led to MISO exceeding its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system. The ISO made emergency energy purchases from Southern Co. before operations returned to normal.
“I, for one, get extraordinarily nervous when there is a disagreement or misunderstanding between our operators,” said Brown, who noted the meetings are continuing.
He said SPP added three new members during the previous quarter, bringing its membership to 97. The newest members include the Crocker Wind Farm, Walmart and NextEra Energy Transmission Southwest. Walmart joined as the RTO’s first large retail customer, a segment that has existed since 2003.
Brown also said that halfway through SPP’s fiscal year, the RTO has over-collected $8.4 million from members. Revenues are up because the number of completed interconnection studies and network services billing have both exceeded projections, Brown said.
An over-recovery this year will reduce rates in 2019, when this year’s actuals are reconciled with budgeted figures.
Board, Members Honor SPP RE Leadership
The board and members recognized SPP Regional Entity Trustees Mark Maher and Steve Whitley and RE President Ron Ciesiel with resolutions and applause following a final report. Dave Christiano, the trustees’ chair, was not present, spending his time instead in Ecuador following his passion for botany.
Maher said the RE successfully transferred 825 GB of data and more than 687,000 files to the Midwest Reliability Organization, SERC Reliability Corp. and NERC. The RE ended all compliance monitoring and enforcement activities for its 122 registered entities on June 29, with the MRO and SERC taking over those duties. (See SPP RE Ending Compliance Monitoring, Enforcement Activities.)
The trustees will hold a conference call Aug. 30 to officially terminate the RE’s regional delegation agreement.
Stakeholders Look at Changing Admin Fee’s Recovery
MOPC Chair Paul Malone said John Olsen of Evergy will chair the task force charged with developing a new rate structure allowing SPP to recover its administrative costs from energy transactions. (See SPP Stakeholders to Study Admin Fee Changes.)
The Schedule 1A Task Force is holding its first meeting Aug. 8 at the Dallas/Fort Worth International Airport. It is expected to report back with recommendations in January.
Stakeholders Add 3 to Members Committee
Members approved three new representatives to the Members Committee during a special meeting of the committee: Northwestern Energy’s Bleau LaFave (Investor Owned Utilities), NextEra Energy Resources’ Holly Carias (Independent Power Producer) and Walmart’s Chris Hendrix (Large Retail Customer).
LaFave’s term ends in 2019, those of Carias and Hendrix in 2020.
Members also approved removing from the bylaws references to the RE, while incorporating a de minimis investment requirement. FERC’s Orders 888 and 2000 bar grid operators, staff and non-stakeholder directors from holding financial interests in any market participant and require them to maintain independence from “any entity whose economic or commercial interests could be significantly affected by the RTO’s actions or decisions.”
Board Approves $47M in Near-term Projects
As part of its consent agenda, the board unanimously approved the Integrated Transmission Planning process’ 2018 near-term assessment portfolio, a package of 13 projects in six states with an estimated total investment of $47 million.
The portfolio is expected to resolve 101 reliability needs resulting from increased load in the Texas Panhandle and announced generation retirements along the Kansas-Missouri border. Notices to construct will be issued by Aug. 21, staff said.
The projects include a new 345-kV, 50-MVAR reactor at City Utilities of Springfield’s (Mo.) Brookline substation, originally identified as an interregional project with Missouri’s Associated Electric Cooperative, Inc. (See SPP: No Need for Joint Study with AECI in 2018.)
Six previously approved projects, expected to cost $85 million, were removed from the assessment because they were no longer needed.
Consent Agenda Includes 11 Revision Requests
The consent agenda also included a recommendation that Oklahoma Gas & Electric’s Jerry Peace fill a vacancy on the Finance Committee; a new baseline cost estimate for Southwestern Public Service’s 115-kV loop rebuild in West Texas; approval of NorthWestern Energy’s sponsored upgrade of a new 115-kV line in Aberdeen, S.D.; charter changes to the Model Development and Reliability Compliance working groups; and 11 revision requests:
CTPTF RR279: Modifies the competitive project proposal process to allow a re-evaluation request before awarding a notice to construct.
MWG RR177: Clarifies references to NERC standards in the Integrated Marketplace’s protocols and the Tariff’s Attachment AE, the marketplace’s governing rules to eliminate confusion over whether entities are performing obligations for market reasons or compliance with NERC standards. The change also modifies the attachment’s definition of operating reserve to that defined in the Tariff.
MWG RR266: Allows any resource to elect to be a combined ownership resource through the modeling option. Those that choose this option will be run through the market-clearing software as a single resource, with post market revenue allocations dispersed to each share based on designated ownership percentages.
MWG RR277: Corrects language in Attachment AE to accurately reflect the settlement formula for the auction revenue rights daily amount by reversing the sequence of the source and sink.
MWG RR304: Streamlines the process by which frequently constrained areas are re-evaluated, to make adjustments in a timely manner.
MWG RR306: Minimizes potential gaming opportunities identified by the MMU. The change allows market-committed resources that have a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period.
MWG RR310: Adds three reporting requirements to comply with FERC Order 844: zonal make-whole payment reports, resource-specific make-whole payment reports and operator-initiated commitment reports. Also requires public posting of transmission constraint penalty factors; the circumstances in which violation relaxation limits (VRLs) could set prices; and procedures for temporarily changing VRLs in the Tariff.
ORWG RR309: Removes section 7.3.1 (FAC-011-3 System Operating Limits Methodology) from SPP’s planning criteria and places it in a separate document for reliability coordination purposes.
RTWG RR278: Corrects Attachment O’s Addendum 1 to include only current and applicable interregional coordination agreements and an update link to the joint operating agreement with MISO.
RTWG RR314: Adds clarifying language to the ITP manual addressing ambiguity in the base reliability and short-circuit model builds.
RTWG RR315: Removes references to the RE from governing documents.
ERCOT executives said Tuesday that system generation has overperformed during the summer, helping the grid operator meet demand during July’s record heat and loads.
| ERCOT
“We saw a real test of the system,” CEO Bill Magness told the ISO’s Board of Directors. “The fleet performed well, and everyone in the market was very aware of what was coming and what we needed to do. It was a good testament to how the participants in the market can perform and how they worked in a stressed situation.”
ERCOT, which manages about 90% of the Texas grid, set a new systemwide peak of 73.3 GW on July 19, breaking the record set in August 2016 by more than 2 GW. Its new weekend demand record of 71.4 GW on July 22 also broke the old mark of 71.1 GW.
All told, demand exceeded the old record during 14 intervals over July 18-23. Demand exceeded 70 GW between July 16 and 24 as a dome of high pressure settled over the state and sent temperatures into triple digits and some heat indexes to about 110 degrees Fahrenheit.
Staff this spring projected a summer peak of 72.97 GW in August.
Having plenty of generation to call on was key, said ERCOT Senior Director of System Operations Dan Woodfin. He noted generation outages in July were “significantly lower” than what the grid operator has historically seen.
ERCOT began the summer with 78.2 GW of available capacity and added 612 MW of gas generation in July. Wind power averaged daily output of 6.6 GW in July, above pre-summer expectations of 4.1 GW.
“The peak day, the 19th, the outages were almost 2,000 MW less than on the peak day last year. We saw that pretty consistently over that period,” Woodfin said. “The cooler weather that we’ve had the last couple of weeks has allowed the units to regroup and fix some things.”
The availability of generation helped minimize tight conditions and keep prices stable. Forward contracts for August delivery reached $239/MWh in May, but they have since fallen back into double digits.
Kenan Ogelman, ERCOT’s vice president of commercial operations, said the operating reserve demand curve (ORDC) has worked as designed. The ORDC creates a real-time price adder reflecting the value of available reserves; it is meant to incentivize resources to produce more energy and reserves.
“The pricing outcomes we’ve seen in the market are associated with expectations,” Ogelman said. “The incentives are also there to put power online, at the times they’re needed.”
He said congestion in the West region, driven by high load growth and combined with the way ERCOT produces load distribution factors, did lead to more than $30 million in uplift costs in June alone. “Wow!” one board member near an open mike exclaimed.
Staff shared operational data from May and June but promised additional information during the board’s October meeting.
“We’re pleased with how it all went, but it’s only Aug. 7,” Magness reminded the board. “We have a lot more August and September to go.”
Below-normal temperatures and rain have helped cool things off over the last week.
“This week has sort of been a dud, and next week won’t be much different,” said the ISO’s senior meteorologist, Chris Coleman. He said “there’s always an opportunity” that extreme heat will return in the next three or four weeks.
