SPP says it has successfully implemented system changes required by FERC Order 809, which ordered RTOs to improve the alignment of their market schedules with those of interstate gas pipelines (RM14-2). SPP’s changes took effect Sept. 30.
“After roughly two months of operational experience, it appears it’s successful so far,” SPP legal counsel Joe Ghormley told a meeting of the Gas Electric Coordination Task Force last week, where he shared the draft of an informational report to be filed with FERC.
The report says “the changes have improved coordination between the SPP markets and natural gas nomination cycles while taking into account stakeholders’ price formation concerns as well as the relative immaturity of SPP’s market and the resulting need for an incremental approach to market system changes.”
SPP described “a year of transition” involving the revised market schedule and the development of system changes for the RTO’s enhanced combined cycle system initiative, the subject of proposed Tariff changes filed with FERC in November (ER17-358). The report also details “extensive efforts” to reach out to and train members and stakeholders. SPP said it is only aware of one resource that has reported potential problems with gas availability, which occurred after a pipeline was taken out of service last December for repairs. When the line was returned to service, it operated below capacity because of reductions mandated by the Pipeline and Hazardous Materials Safety Administration.
“SPP continues to work … to identify cost-effective ways to further compress its market system solve times without jeopardizing the [Integrated Marketplace’s] fundamental functions … or its upcoming enhancements to commitment and dispatch of gas generators utilizing the most efficient configuration of components.”
The report will be filed with FERC on Thursday. The commission required SPP to file an annual report on its compliance with Order 809 for the next three years.
SPP, AECI Narrow Target Areas to Southern Missouri
SPP and Associated Electric Cooperative Inc. have whittled a list of five target areas under consideration for joint transmission projects down to one.
SPP and AECI staff told the Interregional Planning Stakeholder Advisory Committee on Friday that they are still narrowing down different transmission solutions to address high voltages and overloads in the Brookline area of southern Missouri. Planners intend to issue a draft report for the IPSAC’s review early next year.
The two entities currently use an operating guide to manage their seam, but the cost is becoming too big to ignore. Staff said it is considering the use of transmission reactors around Brookline instead of using the operating guide to control voltages. Any final solutions will be coordinated with SPP’s 2017 Integrated Transmission Planning’s 10-year assessment.
SPP and AECI determined three other target areas can be managed without joint projects. The fifth target area, in Northeast Oklahoma, was removed from consideration because a change in transmission ownership shifted facilities to AECI’s management.
Based in Springfield, Mo., AECI is owned by six regional generation and transmission cooperatives.
M2M Payments Flow Back to SPP
Market-to-market payments between SPP and MISO reverted to previous form in October, with MISO paying SPP almost $2.2 million for 871 binding hours on 34 flowgates along the seam.
MISO paid more than $2.2 million for 27 temporary flowgates, while SPP sent about $29,000 to MISO for seven permanent flowgates.
SPP had paid its counterpart for binding flowgates the previous three months, but MISO has sent about $10 million to SPP since the two RTOs began the process last year.
CARMEL, Ind. — FERC has extended the comment period on MISO’s proposed forward capacity auction to Dec. 14 (ER17-284).
The extension — requested by the Public Utility Commission of Texas and not opposed by MISO — should not affect the RTO’s ability to implement the auction in time for the 2018/19 planning year, said Richard Doying, executive vice president of operations and corporate services.
At the Board of Directors’ Markets Committee meeting on Dec. 6, Independent Market Monitor David Patton told the board he was preparing a filing for next week to express his ongoing concerns with the proposal. (See MISO Files Forward Capacity Auction Plan with FERC.)
Director Phyllis Currie asked if MISO had given thought to a contingency plan if FERC takes longer than expected to decide. Doying said MISO is holding off on releasing alternate plans for now.
MISO Awaits FERC Queue Decision
MISO expects a decision from FERC on its queue reform proposal by year-end, Vice President of System Planning and Seams Coordination Jennifer Curran said.
Curran predicted gradual queue improvement in 2017 as the new rules are phased in.
At the September board meeting in St. Paul, Minn., Curran said MISO is hoping to build more certainty into the process that would reduce restudies and the amount of time it takes for projects to clear the queue. “It’s currently a two- to three-year process and is challenged by restudies,” she said.
FERC rejected MISO’s first proposal in March, saying the RTO improperly assumed the current backlog could be blamed on “speculative” projects and “fail[ed] to consider other potential factors” (ER16-675). (See MISO: Stakeholders Behind 2nd Queue Reform Attempt.)
LITTLE ROCK, Ark. — SPP’s Board of Directors last week approved a 13.2% increase in the RTO’s administrative fee and a 6.6% boost in its budget for 2017. The approval came Dec. 6 after a unanimous vote by the Members Committee.
The vote means the fee will rise from 37 cents/MWh to 41.9 cents/MWh in 2017, based on a net revenue requirement (NRR) of $160.5 million, a $9.9 million increase over 2016.
| SPP
The RTO projects annual fee increases for the next five years, reaching 49.9 cents/MWh in 2021.
SPP is projecting an under-recovery of $5.9 million from the 2016 NRR. Other factors contributing to the NRR’s increase are a $3.5 million increase in maintenance expenditures and a $2.7 million increase in personnel costs.
SPP Director Harry Skilton, chair of the Finance Committee, said a decline in load growth led to the administrative fee’s increase. SPP had budgeted 407.2 million MWh in billable energy but revised that down to 393.9 million MWh. It is budgeting 383 million MWh through 2021.
“That reduction in load has set us up for an under-recovery that carries on to the next year,” Skilton said.
SPP budgeted a net loss of $35 million this year but has upped that to a $41.6 million loss given the under-recovery.
The board approved a budget with $194.1 million in income and $196.4 million in expenses for 2017. The 2016 spending plan had $176.2 million in income and $217.8 million in expenses.
The budget sets SPP’s headcount at 610 employees, an increase of one from 2016.
Besides a few questions on SPP’s practice for depreciating expenses, members quickly accepted Skilton’s report and recommendations.
Michael Desselle, SPP vice president and chief compliance and administrative officer, told the board and members that the RTO sent out nearly double the usual amount of stakeholder satisfaction surveys, but that the final results were not significantly different than previous years.
Desselle said the annual survey’s average satisfaction scores dropped for every service except one, by a difference of 0.12 points (out of 5) or less. Training was the lone exception, rising by 0.03.
Stakeholders identified the Z2 revenue crediting process as a repeat theme in their comments. One stakeholder said “the ‘Z2 Monster’ has been an unqualified disaster … I tip my hat to SPP management’s ability to skirt their contribution to the situation,” while another dinged SPP staff for “allowing too many years to transpire before implementing Z2.”
“Last year, [the concern] was the transparency of the Z2 process,” Desselle said. “This year, it was the expediency of the Z2 process.”
As in past years, Desselle said staff will prioritize the comments and address them. He said staff has closed 71 of last year’s 76 comments.
Among the positive comments were many praising the staff’s professionalism, responsiveness and communication efforts. Criticisms included the lack of detailed settlement reports in the Integrated Marketplace portal and what one called the “patronizing attitude” of staff and board members. One critic called for an external market monitor, saying there are “way too many conflicts of interest with an internal” monitor. (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)
SPP distributed 4,597 survey invitations to organizational group members, market participants and other individuals who had interacted with the RTO during the previous 12 months, either through meetings, training, customer relations or other exchanges. Staff received 716 responses, for a response rate of 16%, up one percentage point from last year (410 responses) and four points from 2014 (181 responses).
Desselle also said auditing firm KPMG issued an unqualified opinion with no exceptions following its Statement on Standards for Attestation Engagements (SSAE) No. 16 audit. He said auditors found “no disagreements with management” and that “no illegal acts came to their attention.”
Stakeholders Again Give Organizational Groups High Marks
SPP’s annual survey of its organizational groups matched that from 2016, with stakeholders rating groups’ overall effectiveness at 4.2, out of a possible 5.
The scores reflected the average response to “Please rate the overall effectiveness of this group.” The individual group scores ran from 3.5 for the Event Analysis Working Group to 4.8 for the Human Resources and Oversight committees and the System Protection and Control Working Group.
SPP CEO Nick Brown said he was pleased with the survey’s 71% response rate, and he assured the board and members that SPP “is not just gathering this data and doing nothing with it.”
Ciesiel Pleased with RE Survey Results
Regional Entity General Manager Ron Ciesiel said he was happy with the RE’s stakeholder satisfaction survey, which produced scores of 3.9 to 4.4 on a 5-point scale for customer service and responsiveness, and 3.2 to 3.6 for how well the program meets expectations.
Ciesiel noted RE staff is seen as responsive, knowledgeable, professional and personable and that members see the RE’s workshops on reliability issues as “valuable.”
“Here’s the good news: We’re not having the events we need to do analysis on. We’re not really getting events,” he said. “I’ll take this every day, because it’s good news across the board, not only here, but in North America.”
Ciesiel said the RE is considering a spring workshop and including sessions on new standards. It will also use the RE’s newsletter to focus on the top 10 violated standards.
Paul Malone, Todd Fridley Approved as MOPC Chairs
The board and members unanimously approved the Nebraska Public Power District’s Paul Malone as the incoming chair of the Markets and Operations Policy Committee. Malone, NPPD’s transmission compliance and planning manager, replaces SouthCentral MCN’s Noman Williams, whose term expired.
Todd Fridley, vice president at Transource Energy, was approved as the committee’s vice chair.
The board and members also approved revisions to the Corporate Governance Committee’s charter to formalize bylaw revisions that added committee seats for federal power marketing agencies and independent transmission companies. Bob Harris (Western Area Power Administration-Upper Great Plains) and Brett Leopold (ITC Great Plains) currently fill those respective seats.
Also approved was a charter change for the Seams Steering Committee. It changes the committee’s scope of review and guidance activities from “existing seams agreements” to “new or existing seams agreements.”
Carbon dioxide allowance prices dropped 22% at the 34th Regional Greenhouse Gas Initiative auction on Wednesday, renewing calls from environmentalists to tighten emission limits in the nine-state compact.
Carbon prices have flattened out as the program’s success in limiting emissions has led to an oversupply of emission credits, advocates say. Prices are 53% lower than they were a year ago. Last week’s clearing price is the lowest since December 2013, when 38.3 million allowances cleared at $3.
Brayton Point Power Station | Wikipedia
RGGI is now undergoing its quadrennial Program Review, which will map out 2020 and beyond.
“We now have eight years of experience demonstrating that the electric sector can achieve ambitious emissions reductions at low costs; it’s time for that experience to be reflected in ambitious reforms,” Peter Shattuck, director of the Acadia Center’s Clean Energy Initiative, said in a statement. “The states must use the Program Review to establish more stringent cap levels through 2030 and to implement program design elements that account for the continuing decline in emissions.”
Currently, RGGI states have agreed to reduce the cap on emissions by 2.5% annually, with many stakeholders advocating those reductions should be accelerated to 5% annually.
“The elements that made RGGI such a successful program at its inception are just as relevant today,” Katie Dykes, chair of the Connecticut Public Utilities Regulatory Authority and chair of the RGGI Board of Directors, said in a statement. “The use of a market-based system to cap emissions allows for the most cost-effective reductions. And the auctioning of allowances and the reinvestment of auction proceeds provides benefits for consumers while locking in emissions reductions. The program’s flexibility allows it to adapt to changing circumstances and support the goals of nine states across a diverse region.”
The sale netted about $52.5 million for the nine member states’ clean energy and energy efficiency programs. RGGI auctions have raised about $2.6 billion since their inception in 2008.
CARMEL, Ind. — A year into MISO’s stakeholder redesign, member leadership says the stakeholder process is more efficient but that discussions at meetings could use more depth.
The redesign “check-in” was the Hot Topic discussion at the Advisory Committee’s Dec. 7 meeting. Executive Director of External Affairs Kari Bennett said the redesign has cut stakeholder meetings by 22% and that staff posted 81% of meeting materials a week prior to meetings in 2016, compared to 71% in 2015. She also said MISO is working to attract more speakers from outside the RTO for presentations at informational forums. (See MISO Redesign Nears Completion.)
MISO’s sectors praised the consolidation of stakeholder groups, a cleaner process for those wishing to raise issues and the reduction in meetings and repetitive presentations.
The Independent Power Producers, Coordinating Members, End Use Customers and Transmission Dependent Utilities sectors said the redesign had made meetings more effective.
Indiana Utility Regulatory Commissioner Angela Weber said she appreciated the issues tracking process, through which stakeholders who introduce topics can trace MISO’s response. Under the new process, the Steering Committee confers with MISO staff and may assign the issue to a senior committee.
Northern Indiana Public Service Co.’s Paul Kelly said the creation of the Resource Adequacy Subcommittee helped to combine several related issues but that the standard six-month life of a task team isn’t always long enough to fully address an issue.
Dynegy’s Mark Volpe commended MISO’s new video conferencing capabilities that help connect stakeholders.
“It’s not mentioned much, but over this past year, MISO did a technology refresh. … It allows stakeholders in Little Rock and Eagan [Minnesota] to go to the nearest MISO facility and attend meetings. It helped a number of members with limited resources. … MISO needs some kudos on that investment,” Volpe said.
Feedback Process Lacking
Multiple sectors said that MISO’s feedback process has fallen short and asked for more formalization and transparency around the comments it receives. MISO staff usually ask for stakeholder feedback via email within about two weeks of a presentation on a proposal. The RTO summarizes the responses and sometimes shares them — identified by sector only — at follow-up presentations. Some stakeholders have commented on the challenge of keeping up with a heavy volume of feedback requests and MISO’s inconsistent record of publishing comments.
NIPSCO’s Kelly said stakeholders sometimes do not understand where MISO stands on issues and that some members are confused about what feedback requests are open because the requests are only documented on the final slide of presentations.
Weber said it’s difficult to locate meeting materials and issues on MISO’s website. She suggested the RTO create a feedback calendar.
Bennett said MISO may be stuck in a “‘do loop’ of chasing the calendar,” referring to a section of computer code in which an instruction is executed repeatedly. But she said MISO has committed to revamping its website in 2017. She said MISO staff could create a feedback request tracking page on its website.
“Even though we’ve created some efficiencies, there’s still a lot of work going on, and it’s hard for any one stakeholder to keep up,” Bennett said.
“It struck me that stakeholders said the website is hard to navigate and it’s hard to find information. In a world where you can Google and find information across the globe,” an easily accessible website should be a goal, Director Baljit Dail said.
The Organization of MISO States said the process has “led to incremental increases in efficiency, but the impact on effectiveness is less certain.” Alcoa Power Generating’s DeWayne Todd agreed and said that although MISO has gained efficiencies, the meetings may not have gained effectiveness, as little deep discussion takes place.
Mitch Myhre of Alliant Energy asked for MISO to facilitate more stakeholder policy discussions with the Board of Directors. For example, he said, the board and stakeholders could discuss the RTO’s multiyear effort to revise its cost allocation.
“We’re wondering if the meetings are as effective as they should be. We’re wondering if MISO is open enough. Sometimes you get better discussion in the hallway. [MISO staff] are more relaxed. Maybe because you’re in front of people, it’s harder to be completely open,” Weber said. She suggested setting aside meeting time for brainstorming sessions.
“We are in a bit of a rut in terms of how we process subject matter,” Volpe said. MISO is in a pattern of presenting on a given topic, requesting feedback and coming back with refinements in a months-long cycle, he said. “There really isn’t an open dialogue among subject matter experts and stakeholders. We’re in this rut of consistent feedback cycles, but we really don’t have that policy debate. I feel bad for the chair of these committees; they have to watch the clock and make sure someone goes through 30 slides in 20 minutes. That’s not possible.”
Chris Plante of Wisconsin Public Service said stakeholders could come to meetings armed with presentations of their own to prompt deeper conversations. He also said MISO should make member responses public by default.
Director Michael Evans said he’s seen nearly 12 years of stakeholder process, from “the food fight era” to the “pitchforks era.”
“I think we’re at a spot where the dialogue is healthy. Now it’s time to improve the content,” he said.
Director Tom Rainwater said the redesign is a “tremendous” effort. “I think what you’re emphasizing today is continuous improvement,” he said. Rainwater suggested MISO identify what improvements it could accomplish in 90, 180 and 365 days.
“This is your process. It’s not our process,” Director Judy Walsh told stakeholders. “I would encourage MISO to understand how it can better facilitate improvements into the process.”
“Anytime we bring a big group together, you can feel stuck and like you’re talking over one another,” Bennett said, before quoting the Beatles: “We can work it out.”
AC Priorities Take Cue from Subcommittee Purposes
During the meeting, the AC also adopted a set of priorities set forward by the Transmission Dependent Utilities sector that borrow from MISO subcommittee mission statements. (See “AC to Approve One of Two Sets of 2017 Priorities,” MISO Advisory Committee Briefs.)
Sectors voted 13-9 for the TDU’s offering over a slight revision of 2016 priorities proposed by AC leadership. The new priorities seek to implement best planning practices; preserve and enhance reliability; improve market efficiency; ensure resource adequacy; and ensure equitable cost allocation.
For the more than 300 people who attended or live-streamed Raab Associates’ 152nd New England Electricity Restructuring Roundtable last week, however, the only question is how much storage the state is likely to order. The session provided a briefing on both the policies driving the adoption of storage and the companies that are deploying the technologies.
Judith Judson, commissioner of the Massachusetts Department of Energy Resources, said the “State of Charge” study produced a surprising result: Up to 1,766 MW of advanced storage could save ratepayers $2.3 billion. Comments on whether Massachusetts should set targets are due Friday.
“We have reduced average consumption in Massachusetts, but our peak demand continues to grow,” she said. “Our top 1% of the hours accounts for 8% of our electric spend. Our top 10% of hours account for 40% of our electric spend. … So [storage] could be a tremendous savings for ratepayers.”
| RTO Insider
California Leads the Way
California has led the nation in mandating storage, with 1.3 GW to be deployed by 2024. Since 2013, 630 MW in projects have been approved, California Public Utilities Commissioner Carla Peterman said.
“The commission has to determine that these projects are viable and cost-effective. Typically, that requirement has not been placed on emerging technologies. For example, there is not a similar requirement on our solar incentives,” said Peterman, who participated via video.
Jesse Jenkins, of the Massachusetts Institute of Technology Energy Initiative’s Utility of the Future study, said the two-year effort that will be released this week includes an examination of the impact of distributed storage resources.
Jenkins said storage and demand response resources in some locations can have a value three to 10 times greater than a typical distribution node. “They can deliver [cost benefits] to the power system, but only if the incentives are appropriately granular,” Jenkins said.
Roger Lin, senior director of product marketing for NEC Energy Solutions, described the company’s 2-MW, 3.9-MWh battery storage system in Sterling, Mass., which it says will be the first utility-scale project in the state and the largest battery-based system in New England.
The project will provide the town’s municipal utility with a backup during weather-related power outages and a way to save money by shaving its peak usage. He said storage could have saved the town several hundred thousand dollars over a couple hours when the town’s 3-MW solar array became shrouded by clouds at 2 p.m. on a September day and LMPs jumped from less than $100/MWh to more than $500.
“That cloud cover came at the worst possible time, at the system peak, as the pro rata share of transmission charges and forward capacity market charges” is determined, he said.
Vic Shao, CEO of Green Charge Networks, said his company focuses on the software and controls that predict when peaks will come.
“In California, we really focus on demand reduction. California is particularly expensive, with demand charges going up by about 10% a year,” he said.
“When it comes to storage, controls are everything,” said Josh Castonguay, chief innovation executive at Green Mountain Power in Vermont, which has added storage to a 2.5-MW solar array on a capped landfill. “Because at the end on the day, that’s what’s going to unlock all the value streams for you.”
Matthew Morrissey, vice president of Deepwater Wind’s operations in Massachusetts, said the company, which built the first offshore wind plant in the U.S. in Rhode Island, is developing storage capabilities so it can bid into capacity auctions and state solicitations. He said the company recently won a solicitation to provide the Long Island Power Authority offshore wind combined with storage — beating out more traditional gas-fired alternatives on price.
“Even with offshore wind, where we have wonderful peak incidences where demand matches our power curve perfectly, we recognize we must have an offset of storage,” he said.
Fouad Dagher, director of new energy solutions at National Grid, also emphasized the need to install storage where it provides the most benefit. “How do we dispatch it? When do we dispatch it? And that’s very important for capturing the value,” he said. “Where is the best location to place something?”
FERC last week approved ISO-NE rule changes requiring almost 1,100 MW of non-dispatchable generation to purchase equipment allowing them to receive electronic dispatch instructions from the RTO (ER17-68).
Utility scale biomass plants in New England | Innovative Natural Resource Solutions
The new rules, proposed by ISO-NE and the New England Power Pool in October, apply the dispatchability requirements mostly to municipal solid waste (406 MW) and biomass (263 MW) facilities. Also included are 175 MW of non-intermittent hydro generation and 157 MW of resources that exceed the below-5-MW limitation for settlement-only resources.
They will be required to order remote terminal units — and communication circuits to connect them to the ISO-NE network — by Jan. 15, and to become dispatchable within 12 months afterward. The rules, which will be phased in through June 2020, also require intermittent resources participating in the Forward Capacity Market to offer into the day-ahead energy market.
ISO-NE said the changes will improve reliability by eliminating time-consuming manual dispatch and aid price formation by incorporating additional resources into LMPs. Non-dispatchable generators enter the market as price takers and cannot be marginal.
The RTO said the rules also will aid the participation of storage resources, which both consume and inject energy, in the energy market.
The rules are similar to the “Do Not Exceed” dispatch rules FERC accepted in 2015 for wind and most hydro resources (ER15-1509).
Going forward, only solar, nuclear, settlement-only and most external resources will remain non-dispatchable. Demand response resources will remain non-dispatchable until they are fully integrated into the energy market in 2018, according to ISO-NE.
The RTO says it will propose changes to make larger solar resources dispatchable once it has developed a way to accurately forecast their output, similar to its short-term wind forecast system.
In approving the rule changes, the commission rejected contentions from Eversource Energy that the changes violated the rights of qualifying facilities under the Public Utility Regulatory Policies Act.
“A QF is not obligated to participate in the ISO-NE administered energy markets and can instead choose to operate exclusively as a behind-the-meter resource on its host utility’s system and not be under ISO-NE’s direct operational control and not be subject to the proposed revisions,” the commission said.
President-elect Donald Trump last week selected a climate change skeptic as EPA administrator, while his transition team probed the Department of Energy’s climate research and sought ways for the department to aid struggling nuclear power plants. Meanwhile, Congressional Republicans quashed hopes for a bipartisan energy bill.
Pruitt | ScottPruitt.com
The big news in another whirlwind week was Trump’s selection of Oklahoma Attorney General Scott Pruitt, a leader of the 29-state legal challenge to the Clean Power Plan, as EPA administrator.
Pruitt issued a statement through the transition team vowing to save the “billions of dollars drained from our economy due to unnecessary EPA regulations.”
“I intend to run this agency in a way that fosters both responsible protection of the environment and freedom for American businesses,” he added.
In May, Pruitt coauthored an article in the National Review that said the science of global warming “is far from settled.”
The article also criticized the CPP, saying “this EPA regulation, one of the most ambitious ever proposed, will shutter coal-fired power plants, significantly increase the price of electricity for American consumers and enact by executive fiat the very same cap-and-trade system for carbon emissions that Congress has rejected.”
Oklahoma’s Energy Economy
Oklahoma would be required to cut carbon emissions from power plants by almost one-third under the CPP. About one-quarter of all jobs in the state rely directly or indirectly on the energy industry — mostly gas and oil.
In 2014, The New York Times reported that Pruitt had sent letters to EPA and other federal officials — on state government stationary and signed by him — that had been authored by oil and gas companies.
Environmental groups were aghast, but unsurprised, at Trump’s choice. The Sierra Club complained Pruitt’s appointment was tantamount to “putting an arsonist in charge of fighting fires.”
Democrats vowed to oppose Pruitt’s confirmation, saying they hope to win support from some Republican senators. “This is going to be a litmus test for every member of the Senate who claims not to be a denier,” Sen. Brian Schatz (D-Hawaii) said on a call with reporters.
But Pruitt’s nomination will go through the Senate Environment and Public Works Committee, headed by fellow Oklahoman Jim Inhofe, who famously brought a snowball onto the Senate floor in 2015 to illustrate his skepticism of climate change.
‘Studying’ Paris Agreement
Trump, who has called climate change a “hoax” and vowed during the campaign to abandon the U.S.’s commitments under the Paris Agreement, said last month that he had an “open mind” on the subject. (See Trump Sends Conflicting Signals on Climate Change.)
In an interview with Fox News broadcast Sunday, Trump said he was still “studying” the agreement, saying he didn’t want it “to put us at a competitive disadvantage with other countries.”
“As you know, there are different times and different time limits on that agreement,” he said. “I don’t want that to give China or other countries signing agreements and advantage over us.”
If the CPP survives the court challenge, it will not be a simple matter to undo. “Mr. Pruitt and the incoming Trump administration cannot simply rely on their preferences or on baseless claims about science and markets,” Georgetown University Law professor William W. Buzbee wrote last week. “Decades of law, much of it created by conservatives’ judicial heroes, requires presidents and agencies to abide by the rule of law and justify regulatory reversals. They have to take a hard look at science and other underlying facts.”
Interior, DOE Candidates Emerge
Pruitt was just one of the energy-related appointments in the news last week.
McMorris Rogers | Congress.gov
Numerous reports said Rep. Cathy McMorris Rodgers (R-Wash.) will be named head of the Interior Department. Trump has called for opening more federal lands and waters to oil and gas development.
News reports that Trump has chosen ExxonMobil CEO Rex Tillerson as secretary of state were dominated by questions over the executive’s ties to Russia. But the company also has figured prominently in the climate debate.
New York Attorney General Eric Schniederman is leading an investigation into the company for allegedly making misleading statements on the subject in the past. After Tillerson took over as chief executive in 2006, however, the company acknowledged the science behind climate change and expressed its support for a carbon tax and the Paris Agreement.
Perry | Rick Perry
Former Texas Gov. Rick Perry is Trump’s pick for energy secretary, CBS reported late Monday. The Department of Energy was one of three federal agencies Perry vowed to abolish — and the one he was unable to name during a debate in the 2012 presidential race.
Bloomberg reported that other finalists included Democratic Sens. Heidi Heitkamp of North Dakota and Joe Manchin of West Virginia and Ray Washburne, CEO of Charter Holdings, a Dallas-based investment company with interests in real estate and restaurants.
DOE ‘Witch Hunt’?
Meanwhile, Trump’s transition team caused a stir by submitting to the Department of Energy a long questionnaire requesting the names of all employees involved in climate research.
The questionnaire “suggests the Trump administration plans a witch hunt for civil servants who’ve simply been doing their jobs,” the watchdog group Public Citizen said in a statement.
Other questions asked about the social cost of carbon and computer modeling scientists use to forecast future climate changes.
“My guess is that they’re trying to undermine the credibility of the science that DOE has produced, particularly in the field of climate science,” Stanford climate researcher Rob Jackson toldThe Washington Post.
Bloomberg News reported that the transition team also asked how the department can “support existing reactors to continue operating” and what it can do “to help prevent premature closure[s].” The team also asked about obstacles to resuming work on Yucca Mountain in Nevada, the proposed site for disposing spent nuclear fuel until the plan was nixed early in President Obama’s first term. (See related story, Entergy, Consumers Announce Closure of Palisades Nuke.)
Energy Bill Appears Dead
Last week also ended hopes for enacting the first comprehensive energy bill in almost a decade.
Bloomberg said Sen. Lisa Murkowski (R-Alaska), chairman of the Senate Energy and Natural Resources Committee, and ranking member Maria Cantwell (D-Wash.) had reached an agreement with Rep. Rob Bishop (R-Utah) on a package, but House leaders had refused to move it.
“It’s just very frustrating to see Congress again fail to act on energy efficiency policies that have so much bipartisan political, business and public support and that would help so many people and businesses save money on their energy bills,” Alliance to Save Energy President Kateri Callahan said in a statement. “Caught up — this round — in the failure of conferees to produce a comprehensive energy bill, the very important, practical and bipartisan provisions of the Portman-Shaheen Energy Security and Industrial Competitiveness Act (ESICA) are left in the dust bin of yet another Congress.”
CAISO said it will use a recently approved West-wide system reliability measure to ensure that its grid operators have the ability to send power into Southern California when Aliso Canyon gas pipeline restrictions constrain gas-fired generation output.
Peak Reliability — the West’s reliability coordinator — endorsed the new system operating limit (SOL) methodology, which provides Western Electricity Coordinating Council transmission operators the qualified ability to relax seasonal performance standards for “credible multiple contingencies” on a network under emergency conditions.
“That actually ends up meaning that, if we can technically justify it, we don’t have to hold to planning criteria in real-time operations,” Danny Johnson, CAISO senior operations engineer, said during a Dec. 7 market performance and planning forum.
The ISO will employ the new methodology to replace its previous authority to reserve transmission capacity on Path 26 — the major transmission link between the Southern California Edison and Pacific Gas and Electric service areas.
That authority was included in a raft of Aliso Canyon-related market provisions approved by FERC last spring, but the ISO asked to retire the authority this fall when it filed to extend most of the measures for a year beyond their original Nov. 30 sunset date. (See FERC OKs One-Year Extension for CAISO’s Alison Canyon Gas Rules.)
Restrictions related to the shutdown of the Aliso Canyon gas storage facility have prompted CAISO to employ a new methodology to ease energy transfers into Southern California under emergency conditions. | California Department of Emergency Services
“Instead, we can use the Peak SOL methodology to increase transfer capability that the previous internal reservations gave us,” Johnson said.
Johnson explained that WECC path limits are established using pre-contingency power flow studies performed at the time that a path is identified or after an element along the path has undergone a significant change. Transmission paths are not re-evaluated on a regular basis, so SOLs do not account for minor changes in area load profiles or network topologies attributed to outages. The limits also fail to factor in real-time voltage conditions.
“We plan on using our real-time contingency analysis [RTCA] tool to monitor the actual elements that the path is trying to protect,” Johnson said. “This is more accurate because it’s not a pre-contingency proxy limit — it’s actual real-time data, built on voltage data. We’re able to reflect all of the neighboring topology changes either due to system changes or outages, which are constantly occurring,” allowing the ISO to observe a more accurate SOL in real time.
The RTCA tool also enables CAISO to incorporate the use of remedial action schemes — plans designed to automatically initiate corrective actions after detection of certain system conditions — to relieve congestion by strategically shedding load or generation to avoid overloading a line.
The ISO has determined that remedial action schemes (RAS) have “armed” an increasing amount of targeted SoCalEd load for shedding since the SOL for Path 26 was established in 2006.
“So in real time, if we assume that there’s additional load that will be dropped, that’s additional congestion relief that the RAS will provide,” Johnson said.
Use of the RTCA reduces the potential for Path 26 to hit its thermal limit, providing the ISO more latitude in exceeding the line’s 4,000-MW rating when Southern California gas restrictions hobble the region’s generators. The ISO estimates it could squeeze out a “few hundred” extra megawatts of transfer capability on the line under certain real-time conditions.
“We plan to use this only as a last-gasp emergency measure,” Johnson said. “By the time we use this, we will have exhausted all internal generation resources within Southern California, all demand response.”
Because the methodology requires use of real-time data, it cannot be incorporated into CAISO’s day-ahead market, which — along with the real-time market — will continue operating with the path’s current ratings from the ISO transmission register.
While CAISO has set no precise time limit for employing the measure to relieve a constraint, it expects any such event to be of limited duration.
“We want to drive back to the normal limit as soon as possible, so we wouldn’t presumably increase the market limit,” said Mark Rothleder, CAISO vice president for market quality and renewable integration. “So we would bind around that market limit trying to get back, but it would be the cushion to prevent having to drop load.”
Brian Theaker, director of market affairs at NRG Energy, asked whether the ISO intended to limit using the measure for just Path 26.
“At this time, that is where we see this being used,” Johnson responded. “I think that we would be open to using it on any WECC path that we would need to if real-time conditions dictate.”
Noting that CAISO said it could not notify market participants before or during a Path 26 event, Carrie Bentley of Resero Consulting asked what would be the most “preferable way for [ISO operations] to make this more transparent.”
Rothleder said he would have to take that question back to CAISO management.
“I think we may be able to say that these events are fairly rare,” Rothleder said. “If the event happens, we’ll give some notification after the fact, but I don’t want operators having to think, ‘Well I have to get this information out,’ while they’re trying to struggle through the event.”
WILMINGTON, Del. — The increasing complexity of distribution systems is creating a new “seam” for grid operators, representatives from an industry planning collaborative, the U.S. Department of Energy and Johns Hopkins University said at PJM’s General Session last week on the evolution of system planning.
The growth of distributed energy resources is changing the one-way flow of distribution systems, complicating their relationship with the transmission grid, speakers said.
“Transmission and distribution planning and operations are separate, so the problem becomes understanding the changes on one and how they impact the other,” said David Whiteley of the Eastern Interconnection Planning Collaborative. “In the vertically integrated world, I think the two pieces of planning would merge. … We talk about seams issues with neighbors on transmission. You’re going to have seams issues with the distribution.”
Stan Hadley of the Oak Ridge National Laboratory extended the analysis to the natural gas pipeline network. He noted a study of natural gas sufficiency in New England during the winter that found that the constraint was the lack of pipelines across New York.
“They’ve been pushing away on building those pipelines,” he said.
Whiteley said infrastructure planning has become increasingly complex.
“It’s not a predictable load shape anymore. Generation planning is at arm’s length from transmission planning in many regions of the country, so how can you plan the transmission system if you don’t know where the generation’s going to be?” he said. “You don’t know if a line can be built or what year it will possibly come into service. That complicates the prediction of what the future looks like. All of this takes additional time; it takes additional resources.”
Researchers must understand not only the electric grid but also the natural gas distribution system, physical security issues, political dynamics and an ever-growing list of NERC reliability standards, Whiteley said.
“I used to work at NERC, but even I was shocked at the volume — over 100 standards; 3,000 pages of material on the NERC standards,” he said. “Everything is in the context of the search for what I call the ‘Holy Grail of Planning’: co-optimization of everything.”
Whiteley said incorporating complexity increases understanding of the system but makes planning far more time consuming. He highlighted an EIPC study that defined eight resource-planning futures and analyzed three of them 20 years into the future. The single study took two and a half years, he said.
Having to choose between potential scenarios to study is a dilemma that Johns Hopkins professor Ben Hobbs is attempting to eliminate with his research into “stochastic multistage integrated network expansion.”
“The key thing is we’re making decisions today not knowing which paths we’re going to go down,” he said. “What to build now; what to build later; what’s the value of flexibility. … You’re doing this all at once in one large, linear program.”
While Hobbs’ modeling can take days to run depending on the complexity, it’s already shown success in producing otherwise unseen and money-saving guidance. A study for the Western Electricity Coordinating Council uncovered several insights likely to improve the value of transmission planning over a 40-year outlook by approximately $3.5 billion, he said.
“Under proactive planning, you get more transmission and definitely different siting” for generation, Hobbs said.
Another challenge is integrating individual reports into a cohesive overview, Hadley said. Through the Grid Modernization Laboratory Consortium, he is working on standardizing a “common language” for studies so that results can be compared.
“The idea is being able to show your results and other people can see where you came from,” he said. With current procedures, “you sometimes don’t know what the underlying assumptions were.”
