Texas Public Utility Commission Chair Donna Nelson surprised staff and open-meeting attendees Thursday by announcing she would be stepping down in May.
Nelson was appointed to the PUC by Gov. Rick Perry in August 2008. She was named chairman in July 2011 and was appointed by Gov. Greg Abbott to another six-year term in September 2015 that was to expire in September 2021.
“I think you have left a distinguished and wonderful mark on this state with your service,” Commissioner Brandy Marty Marquez told Nelson after her announcement. “There’s a whole lot of gratitude owed to you, by everybody here.”
“I’m not dead yet,” Nelson responded, before getting down to business. “It’s been a great time and we’ve done a lot of important things, so let’s continue that work now.”
Nelson, who said her last day will be May 15, will leave the PUC having served more time than anyone else. However, Commissioner Ken Anderson could soon eclipse her tenure. He joined the PUC one month after Nelson did, and his current term expires in August.
Marquez was appointed to the commission in August 2013. Her six-year term expires in September 2019.
Nelson said she would elaborate on her future plans as her end date nears.
Abbott will appoint Nelson’s replacement as chairman, as well as fill the commission’s vacancy. The PUC oversees ERCOT and Texas electric, telecommunication, water and sewer utilities.
Nelson also represents the PUC on SPP’s Regional State Committee, which provides regulatory input to the RTO. She will be replaced on the RSC by one of her fellow commissioners.
Ironically, Nelson, who is not a fan of personal photos, also said she had “good news”: “I’m getting my portrait taken.”
Her official studio photo will finally join those of the other current and previous commissioners on the PUC’s hearing room’s walls.
Before joining the PUC, Nelson was a special assistant and adviser to Perry on energy and telecommunication issues. She also served as legal adviser to a previous PUC chairman and as a former assistant attorney general for Texas, where she specialized in antitrust law.
A South Dakota native, she received a bachelor’s degree from Black Hills State College and a law degree from Texas Tech University.
TULSA, Okla. — SPP has increased its membership roster to 95 with the addition of Southern Power, the wholesale arm of utility giant Southern Co.
COO Carl Monroe made the announcement Wednesday during SPP’s quarterly Markets and Operations Policy Committee meeting. Southern Power’s membership was effective Tuesday.
Southern Power’s 299 MW Kay Wind Facility in Kay County, Oklahoma | Siemens
Southern Power “is excited to join the Southwest Power Pool as a member and looks forward to collaborating with our fellow stakeholders to help shape the future of energy,” Jim Howell, Southern Power’s transmission and regulatory policy manager, said in a statement.
“We thank you for your contributions to the administrative fee,” cracked MOPC Chair Paul Malone, with the Nebraska Public Power District, addressing a company representative at the meeting.
Southern Power owns four wind farms in SPP’s footprint, three in Oklahoma (totaling 597 MW of capacity) and the 276-MW Bethel Wind Facility in the Texas Panhandle.
The company’s portfolio includes 46 natural gas, wind, solar and biomass generating assets spanning all four time zones.
MISO is considering prohibiting resources on extended outages from participating in future Planning Resource Auctions or making changes to capture the risk of such outages in loss-of-load-expectation (LOLE) analyses.
Manager of Resource Adequacy John Harmon said MISO wants stakeholder feedback on whether resources on extended outage should be disqualified from PRA participation or if costs of possible outages should be shared by revising modeling assumptions in the annual LOLE study that informs the RTO’s planning reserve margin. The changes would not affect PRA 5, the results of which are due to be released Friday.
Harmon told the April 12 Resource Adequacy Subcommittee meeting that MISO’s Tariff does not prohibit participation of generators on outage for “significant portions of the planning year.” Each year, up to 10 generators providing capacity go offline on outages lasting 90 days to a year, including the summer peak, although the outages are known before the PRA is conducted, Harmon said.
He also said the RTO currently offers an Attachment Y suspension notice for outages longer than 60 days, but use of the form is not mandatory.
MISO recommended stakeholders seek an immediate fix for the 2018/19 planning year and seek a long-term solution afterward.
Harmon asked stakeholders to respond by April 26 with the minimum outage length that should disqualify a resource from PRA participation. Harmon also asked if stakeholders thought generators should be penalized or made to procure replacement capacity if an outage occurs during the planning year. Currently, generators on outages forfeit only their capacity revenue for periods when they are unavailable.
Stakeholders at the meeting asked for evidence to back up the two options.
“I think MISO might be bringing this forward because there’s something they see that we don’t see,” said Consumers Energy’s Jeff Beattie. He asked the RTO to bring evidence back to illustrate the possible risk. Beattie said while he did not see a risk posed by extended outages in his Zone 7 for the next three years, “maybe there’s something else going on with seasonal outages in other parts of the footprint.” Beattie also said there is nothing wrong with dipping into operating reserves to make up for outages.
Ted Leffler of Indianapolis Power and Light asked how often MISO overestimated its seasonal peak in the past and said the RTO should examine both aspects when considering resource adequacy.
Harmon said the problem boils down to the fact that a resource that has completed its generation verification test and identified itself as available during the planning year and then experiences a catastrophic event can still participate in the capacity auction.
“And that’s the worst-case example. There’s a spectrum of events that could happen,” Harmon said.
VALLEY FORGE, Pa. — PJM invited two distributed energy resource developers to explain their operations and presented a case study of its own at Monday’s special session of the Market Implementation Committee. The presentations elicited concern from electric distribution companies, who asked that rules be implemented that keep them informed when customers want to install such systems.
“We simply need to know what’s happening before it happens and not after the fact. That will give us the opportunity to determine what needs to be done,” FirstEnergy’s Bruce Remmel said.
Calpine’s David “Scarp” Scarpignato said stakeholders could benefit from EDCs providing information to PJM on such interconnections. “A lot of small [projects] can add up to big numbers,” he said. “It seems to me like the notification should go two ways.”
PJM discussed a recent visit by staff members to Hopewell Valley Central High School in Pennington, N.J., where Public Service Electric and Gas has installed a solar and battery system. The 580-kWh Hopewell battery is an “in front of the meter” system but doesn’t qualify as an “energy storage resource,” PJM staff said, because it is primarily a backup power system for the school during an outage and therefore doesn’t fit the definition of a storage resource. Instead, it’s accounted for under “station power” rules, even though it provides regulation, capacity and energy services to the RTO.
Hopewell Valley Central High School Solar Storage Project | PJM
PJM’s Andrew Levitt, who led the presentation, explained that a resource can be designated either in front of the meter — meaning it’s able to provide capacity and energy services — or behind the meter, meaning it can be used to net against load for wholesale transmission, capacity and ancillary services charges. The same megawatts cannot be used for both simultaneously, he said.
Drew Adams of A.F. Mensah and Adesh Harripersad of Distributed Asset Solutions highlighted how their businesses have handled installations of both types of resources in PJM.
It was A.F. Mensah’s problem statement and issue charge that precipitated development of the special sessions, borne out of the challenges faced with PJM’s policies on how systems combining batteries and renewables must be interconnected. (See PJM Considering Injection Rights for Demand Response.)
The company has moved forward with projects using the existing rules while they’re being discussed in this stakeholder process.
Adams highlighted some of the challenges and experiences when complying with all existing rules. Adams said his company paid a $500 application fee for each of 20 installations and that the installations are aggregated in PJM’s models as a single 0.1-MW market resource. He presented diagrams showing how the projects require two separate electric service lines to an end customer site: one for the existing service line including behind-the-meter solar panels, and a new service line for the battery storage system so its capabilities can be sold directly into PJM. The battery system acts independent of the customer load and solar in normal operation and is then connected to the load and solar through redundant switch gear during a bulk grid outage.
He explained that the systems have five meters, each providing different information to different recipients. FirstEnergy’s Ed Stein said that creates concerns because partial information may make it impossible to fully understand what’s going on with a system.
“Ultimately, I think there will be a lot more information sharing between EDCs, transmission owners [and] PJM,” Stein said. “We’re going to have to come up with an information-sharing paradigm that works for everybody. We may find ourselves that not one single entity has all of the information or ownership of all information at its disposal to give. … We’ve got a lot to consider with information here: who’s going to have it, who’s going to provide it, who’s going to be able to see it and access it and understand it.”
| A.F. Mensah
Adams said his company is supportive of those discussions.
Harripersad discussed the coordination issues that make project development and construction difficult. He works with funding provided by True Green Capital Management to develop photovoltaic solar arrays throughout the country. Even with long lead times — with delays created by the need to secure everything from state environmental approvals to local construction permits — projects are often a rush at the end, he said.
“All these things add up to, literally, down to the wire; you have three months to build everything,” he said. “The big thing is getting our projects interconnected.”
He praised project coordination among stakeholders within PJM’s footprint. “This coordination is unheard of in any other [RTO or ISO] territory in the country,” he said. He referenced a 16.7-MW solar rooftop project with the Port of Los Angeles in which he said CAISO has “no involvement.”
Work began on collecting stakeholder interests and potential solutions but didn’t get far, only advancing to design component 1.2. PJM staff assured this would be a main focus for the group’s next meeting.
More than two decades after initiating a deregulation drive that faltered in the wake of the Western Energy Crisis of 2000/01, California officials are taking another look at offering consumers the ability to choose their electric supplier.
This go-round should be different, according to the state agencies heading up a new exploration of “the changing state of retail choice” in California, because of changes already in motion.
“Unlike electricity restructuring efforts of the past, when policymakers made a set of conscious decisions to move to open market competition, this transition is being driven by a range of economic and technological trends,” the California Public Utilities Commission and California Energy Commission said in a joint statement April 11.
To kick off the effort, the two agencies will hold a May 19 joint en banc public hearing to identify the “challenges and opportunities” stemming from “fast-approaching” changes overtaking the industry. The goal is “to ensure that reliable and low-carbon electricity will be available to all California consumers,” the agencies said.
Key among the factors now influencing the sector: the rapidly falling costs for renewable and energy storage technologies, which the CPUC and CEC say are “upending the nature of electricity service.”
The agencies estimate that by the end of this year, up to 40% of the state’s investor-owned utility customers will be receiving “some type” of electricity service from an alternative source, such as rooftop solar, community choice aggregators (CCAs) and direct access providers.
California officials are reconsidering the idea of “consumer choice” for retail electricity customers who continue to pay some of the highest rates in the country. Efforts would focus on giving more residents affordable access to renewable resources that help the state meet its environmental mandates. | U.S. Energy Information Administration, Form EIA-861, “Annual Electric Power Industry Report.”
California today boasts nearly 5,200 MW of installed rooftop solar capacity, according to California Distributed Generation Statistics, a website sponsored by the CPUC and the state’s IOUs. The state also has six CCAs, with more slated to begin operation within the next few years, a development that is expected to increasingly siphon off the customer base from the traditional IOUs.
“The implications of this migration away from ‘bundled’ utility service were not fully contemplated when the current regulatory rules were developed,” the agencies said.
The changes provide “tremendous opportunities” for California to meet its carbon reduction goals, but they will also create “unforeseen risks,” the agencies said.
The May 19 hearing will offer a closer examination of those opportunities and risks. A preliminary agenda indicates the event will start with a presentation on a still-pending CPUC white paper on retail choice, followed by an overview of the current state of retail choice in California and panel discussions focused on the perspectives of both the IOUs and electricity customers.
The agencies will also invite national electricity market experts to share their perspectives on retail choice in other regions, the role of technology in transforming electricity service and how California can restructure its regulatory framework and markets to help achieve its public policy goals.
California last set a course for deregulation in 1996 with the enactment of Assembly Bill 1890. Under the law, regulators first set out to restructure the state’s wholesale market while leaving retail price controls intact. The ensuing crisis — which resulted in the 2001 bankruptcy of wholesale market operator California Power Exchange — precluded the implementation of any retail market measure. Wholesale operations now reside with CAISO, which in 2009 rolled out a nearly statewide energy market designed to prevent the kind of manipulation that crippled the exchange.
Western state utility commissioners on Monday expressed support for providing the Energy Imbalance Market (EIM) Governing Body with increased authority over changes to the market’s governing charter.
The commissioners also agreed on a set of measures that would streamline the process for convening calls and meetings of their own EIM-related group, the Body of State Regulators (BOSR).
BOSR members were scheduled to hold a nonbinding vote on whether to endorse the charter revisions during the April 10 teleconference, but the group fell two members short of a quorum, which requires the presence of commissioners from five of the eight states in the EIM footprint.
In an April 5 memo, CAISO management proposed that any “substantive” modifications to the charter be first presented to the Governing Body for its “advisory” input — similar to the role body members play regarding ISO market rule changes that also affect the EIM. (See EIM Charter Changes Would Give Governing Body More Power.) The ISO initiated the move at the request of Governing Body Chair Kristine Schmidt.
Other revisions would enable the Governing Body to initiate changes to portions of the charter dealing with the BOSR and the Regional Issues Forum.
The Governing Body plans to present the changes to the CAISO Board of Governors, which is charged with reviewing any charter amendments during its May meeting. The board must formally approve any changes to the charter, but in practice it gives wide latitude to the Governing Body’s decisions on solely EIM matters. Timelines dictate that the amendments will advance without the BOSR’s formal endorsement, which is not required.
The state commissioners who spoke on Monday’s call voiced their informal support for the changes. No one expressed any opposition. They were relying, in part, on the advice of the commissions’ staffs.
“The official recommendation from the Advisory Committee is that you approve and support [the changes] to the Governing Body,” said Brian Thomas, policy director with the Washington Utilities and Transportation Commission and a member of the EIM Staff Advisory Committee.
Thomas noted that WUTC Commissioner and BOSR Chair Ann Rendahl — who couldn’t participate in the call because of a schedule conflict — supported the changes.
Changes ‘Make Sense’
White
Utah Public Service Commissioner Jordan White agreed with the staffs’ recommendation and the CAISO memo outlining the changes.
“It makes sense,” White said. “It’s consistent with how the charter works in terms of certain issues that go to [the] consent [agenda] of the full Board of Governors.”
“I don’t see any reason that we would oppose it, but it sounds like we’re not making any decision today, so I’ll take a look and get back with everyone,” said Oregon Public Utility Commission Chair Lisa Hardie.
Hardie
White apologized to Schmidt for his group’s inability to provide full approval.
“Thank you very much for going ahead with the discussion,” Schmidt replied. “Because if there were some issues or concerns that any of the Body of State Regulators would have, we would want to know about that.”
The submission of a written recommendation from the Advisory Committee would be helpful to the Governing Body in its own deliberations, she added.
“I can write something up that summarizes what the staff committee did and recommended and provide that to you,” Thomas responded.
Speaking on behalf of the BOSR, White told Schmidt: “We appreciate the opportunity to at least have a say in this.”
‘Willingly Pay’
Commissioners also backed proposals to allow CAISO to post BOSR meeting agendas on the ISO’s website and to use its audio conferencing system to host calls.
Among those voicing support for the move was White, who pointed out that Rendahl and her WUTC staff had been “carrying the water” of setting up the agendas and conducting BOSR meetings.
“We had reached out to [Rendahl] and mentioned that we would be happy to host and just try to take some of that administrative burden off of the group,” said Peter Colussy, CAISO external affairs manager.
“I think we’re comfortable with that,” Hardy said. “It seems like that would functionally work just fine from our perspective.”
“Speaking for the Washington staff that’s been doing this, we would willingly pay CAISO to take over this stuff,” Thomas joked.
The commissioners also endorsed the idea of subsuming the BOSR’s infrequent in-person meetings into those held by the EIM Governing Body.
“I think the jury is still out on how often to have [BOSR] meetings,” White said.
Because of the lack of quorum during the April 10 call, the meeting-related proposals were tabled by the BOSR until its next call on May 30.
VALLEY FORGE — PJM staff on Friday detailed how the new rules for aggregating seasonal resources will be implemented in May’s Base Residual Auction, the first requiring all resources meet tougher Capacity Performance standards.
FERC staff tentatively approved PJM’s aggregation proposal March 21, allowing the RTO to relax current rules prohibiting seasonal resources from aggregating across locational deliverability areas (LDA) (ER17-367). PJM’s plan also creates additional winter capacity interconnection rights (CIRs) and modifies rules for measuring demand response performance in the winter. (See FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible.)
The May BRA, which will provide capacity for delivery year 2020/21, will only procure resources available year-round, ending PJM’s longstanding use of summer-only DR and energy efficiency.
PJM’s Pete Langbein, Paul Scheidecker and Jeff Bastian told the Demand Response Subcommittee on Friday that there will be two aggregation categories:
Commercial aggregation, in which a market seller will match seasonal resources on its own and offer them together as a single year-round capacity resource. All resources must be within a single capacity market seller account.
Facilitated aggregation, in which seasonal resources offer into the BRA individually and will be grouped with complementary resources by PJM.
Eligible for aggregation will be intermittent generators, energy storage, environmentally limited resources, DR and energy efficiency. Winter resources (November-April) would be matched with summer resources (June-October and the following May).
PJM will clear all annual CP offers, summer-period offers and winter-period offers simultaneously to minimize the cost of satisfying the reliability requirements of the RTO and each modeled LDA. Total cleared summer-period offers must exactly equal total cleared winter-period offers across the entire RTO to ensure coverage for the entire year.
Commercial resources must be submitted to PJM for analysis and approval no later than two weeks before the BRA, or April 26.
When commercial offers are submitted, they must include an explanation of how the aggregation achieves a higher CP ability (measured in unforced capacity megawatts) than the resources individually. PJM will respond with the approved megawatt offer and what LDA the aggregate will be modeled in.
Cleared resources will receive a blend of the clearing prices of the LDAs in which the resources are located, Langbein said. Market sellers are guaranteed that the blend will be at least the resources’ cleared offer prices.
Seasonal resources can be replaced using a “similarly located” resource from any source, whether it’s an annual CP resource or an appropriate seasonal one. They can also be replaced in an Incremental Auction but would need to be bought in the same LDA the resource is physically located in.
For commercial aggregates, replacements can be from any LDA but must be available CP resources or cleared CP buy bids. “What you are not able to do is go in and replace the constituent components of your aggregate,” Langbein said. “So you can’t go in and replace the wind farm, for example, that’s part of your commercial aggregate.”
| PJM
Resources’ production during performance assessment hours (PAHs) will be netted between all of the resources required to perform during the PAH. Penalties for shortfalls and credits for overperformance will be assessed to the aggregate resource, not individual resources.
NRG Curtailment Solutions’ Brian Kauffman asked whether a resource in the same zone as the PAH that is not required, but that performs anyway, would be included as overperformance in the assessment. Bastian confirmed that it would automatically be included in PJM’s calculations.
WASHINGTON — Energy efficiency now accounts for about 1.9 million jobs in the U.S., with double-digit growth projected for 2017.
So how can the Trump administration reconcile its pledge to create jobs with the president’s proposed budget cuts to the Energy Department’s research programs, which have been credited with helping to improve energy efficiency technologies?
“The EE folks have had a pretty good run for the last eight years and it’s time to rebalance a little bit,” energy lobbyist Michael McKenna told the Energy Bar Association’s annual meeting last week.
“You look at the DOE numbers, it tells you everything you need to know. $2.4 billion goes to EE and $670 million goes to the clean coal office and $430 million goes to the nuclear [power] industry [research],” said McKenna, president of MWR Strategies and former lead of President Trump’s transition team for the Energy Department. “The vibe is, let’s rebalance and to the extent possible take the government out of the equation. You can think that’s a good idea or a bad idea. But that’s the idea.”
(Lowell Ungar, senior policy advisor for the American Council for an Energy-Efficient Economy, cites somewhat different figures for fiscal year 2016. The Office of Energy Efficiency and Renewable Energy received $2,069 billion, but that includes both efficiency and renewables: Nuclear received $986 million, which includes funding for research beyond power plants; fossil fuels — coal, oil, etc. — $632 million.)
“Of course, how much it makes sense to spend in a given area depends on the potential impacts of the technologies, on how developed the industries are and thus able to support their own research, and on DOE’s capabilities to manage effective projects in the area,” Ungar said.)
McKenna, a registered lobbyist who has represented Southern Co., Koch Industries and GDF SUEZ, resigned from the official transition team last November after Trump announced that no registered lobbyists would be permitted on the “landing teams” that met with agency officials.
McKenna and Shannon M. Bañaga — another lobbyist whose role on the official transition team was cut short by Trump’s directive — recounted their experiences as members of the transition team and their predictions on the next four years for a luncheon audience. Thomas J. Pyle, president of the Institute for Energy Research and former lead of the Energy transition team, canceled his appearance because of an illness.
“What that really meant was that the lobbyists — I think were two or three of us — got about quadruple the amount of work, and the official transition and Tom Pyle, our colleague, was able to meet with DOE … and those of us unsavory lobbyist-types, we got to meet with the rest of the industry and hear about the issues that” concerned them, she said.
“I can’t express to you how many man-hours were put into very specific ideas about what FERC should be working on in the next couple years; what DOE should and shouldn’t be working on,” said Bañaga, an attorney who worked previously for both FERC and Energy and now serves as TECO Energy’s director of federal affairs.
Slow Start
McKenna acknowledged the new administration has been somewhat slow in filling vacancies.
“I know from the outside things look confused,” he said. “Truth to be told, it isn’t any worse than any other transition. The one thing that [they] had a little trouble with is the switch out from the campaign to post-election. And that has shown up in personnel. We have about 497 appointments throughout the federal government that require Senate confirmation. As of four or five days ago, we had about 43 guys in the queue. So we’re a little slower than everybody else. It will probably get better as it goes along. But in all fairness, [he] came in with a Supreme Court justice waiting to happen so that absorbed a lot of mindshare.”
‘Ignore the Circus’
He had advice for those troubled by the Twitter-happy president. “Ignore the circus,” he said. “The president is a fellow who’s used to being on the camera and in the news and chewing up a lot of mindshare. And the media has not yet figured out that sometimes the best thing to do is just [ignore him]. I come from a large Irish Catholic family, and we have a tendency to say, ‘Just give him the nod. Whatever you say, boss.’
“Ignore the circus. Pay attention to what … he actually gets done. And if you think about that, everything that’s been done is pretty much everything you would expect that was going to be done. … From the first time he articulated … what he wanted to do on energy, he hasn’t wavered a lot. … It’s been pretty consistent.”
Electric Role in Infrastructure Bill
Responding to an audience question, Bañaga said utilities are unlikely to seek federal funding for capital expenditures in the infrastructure legislation Trump has promised. “So much of what we [utilities] do is critical infrastructure. From the pipes and wires … we tend to like paying for our own stuff. That’s part of the business [model] and I don’t think we’re going to be very boisterous on saying that we want fed government money for an infrastructure project.”
She said the industry would support efforts to increase workforce training in “STEM” fields — science, technology, engineering and mathematics — in the bill and perhaps cybersecurity.
“Depending on what we’re asked to protect against and the standards we’re going to be held accountable for, cyber and physical security, I think that might be one that gets rolled into an infrastructure package.”
“We’re going to get infrastructure built,” McKenna promised. “The president didn’t run on tax reform. He ran on infrastructure. We’re going to build infrastructure.”
What would it include? “Anything that involves concrete,” he responded.
Changes at FERC?
Another questioner asked whether FERC was likely to be subject to the Trump requirement that agencies eliminate two regulations for every new one.
“I work in front of a lot of federal agencies like a lot of you do,” McKenna said. “The bottom line is, FERC process is, FERC people are the best in the government. So are the [FERC] nominees … going to want to take a hard look at things? Of course. Are they going to wander in knocking things over? I don’t think so.”
Two SPP stakeholder groups have endorsed staff’s recommendation to remove a Southwestern Public Service 345-kV line from projects recommended in the 2017 Integrated Transmission Planning 10-year assessment.
The Transmission and Economic Studies working groups met jointly April 3 to vote on staff’s re-evaluation of the 90-mile Potter-Tolk transmission line in the Texas Panhandle, one of 14 projects in the 2017 ITP10.
SPP’s Board of Directors and Members Committee directed staff in January to further evaluate the transmission line following pushback from SPS, which said it was “the wrong time” for the line. (See “Board Sends $144M Tx Project Back for Re-evaluation,” SPP Board of Directors/Members Committee Briefs.)
Staff gathered feedback from members in the West Texas/New Mexico area to determine expectations on resource expansion, load growth, gas prices and avoided reliability projects. A third-party review using more detailed routing assumptions increased the project’s $144 million cost estimate to $173 million, identifying a need to lengthen the project from 90 miles to 109.
ITC Holdings abstained from both working group votes, saying it believes “more realistic analysis scenarios” provide support for including the project in the ITP10 portfolio. Golden Spread Electric Cooperative abstained from the ESWG vote, citing positive benefit-cost ratios for the scenarios that included 8.8 GW of additional wind. South Central MCN abstained from the TWG vote over concerns with the re-evaluation process and modeling updates and adjustments.
Separately, the TWG unanimously approved the 2017 ITP near-term assessment, which includes 16 reliability projects at a combined cost of approximately $60 million. The Markets and Operations Policy Committee and board will vote on the near-term ITP and take up the Potter-Tolk recommendation at their April meetings.
MISO Tops $15M in M2M Payments to SPP
MISO has paid SPP a net $15.3 million in market-to-market payments since the two RTOs began M2M activity in March 2015, SPP’s Will Ragsdale told the Seams Steering Committee on April 5.
MISO is responsible for seven of the top 10 congested flowgates between the two RTOs, resulting in $12.7 million in M2M payments. SPP has paid MISO $4.3 million for the other three flowgates in the top 10.
SPP’s M2M report for February indicates MISO paid just more than $889,950 for 434 hours of binding temporary and permanent flowgates.
MMU Market Report Shows Wind Up, Coal Down
Wind energy accounted for almost a quarter of all energy produced this winter, according to the SPP Market Monitoring Unit’s State of the Market report released last week.
Wind generation produced 23% of the footprint’s energy this winter (December-February), compared to 18% in 2016 and 15% in 2015. That corresponded with a drop in coal-fueled production, to 52% from nearly 58% in 2015.
The MMU said gas costs continue to rise in the region, with an average of $3.08/MMBtu at the Panhandle Hub, compared to $1.98/MMBtu in 2016. The rise in gas costs also resulted in increased LMPs; the average real-time LMP went from $17.82/MWh in 2016 to $24.57/MWh, and the average day-ahead LMP went from $18.33/MWh to $24.14/MWh.
CARMEL, Ind. — MISO is preparing nondisclosure agreements and associated Tariff language to share gas usage estimates with pipeline operators, but some stakeholders are voicing reservations about the pilot program.
The RTO says the nondisclosure agreements will be required before staff of pipelines or local distribution companies can view hourly burn estimates based on the day-ahead market clearing. “MISO will not share any information before that signed nondisclosure agreement,” Mark Thomas, MISO manager of gas-electric coordination, told the April 6 Reliability Subcommittee meeting.
MISO has lined up three gas system operators for “limited sharing” of day-ahead gas usage profiles in 2017 under the pilot program, an effort to ensure gas-fired generators have fuel when they need it.
The RTO said it will outline the use of the nondisclosure agreements in section 38.9.1(A) of its Tariff and file the changes with FERC by April 26. Thomas asked for stakeholder comment on the language insertion by April 13.
MISO said it would wait for FERC acceptance before sharing profiles. Thomas said the RTO has not yet determined at what frequency the information would be provided.
Multiple stakeholders voiced apprehension that reliability will be harmed if operators act on partial, estimated data provided by MISO. Subcommittee Chair Tony Jankowski questioned why the RTO would move ahead on the program with what he said was incomplete data based solely on day-ahead market activity.
Phil Van Schaack, MISO gas-electric operations coordinator, reminded stakeholders that the program is a pilot and insisted the sharing of generator start and stop times and estimated burn rates will be helpful. “This is a way to start the exchange of some data,” Van Schaack said. “The pipeline operators are excited by this.”
Thomas said if the pilot program does result in the sharing of “bad information,” MISO will scrap the program.
Indianapolis Power and Light’s Lin Franks said that while she is usually “all for” the sharing of information, the pilot program could cause problems. If MISO’s information clashes with generator operators’ information, they might be in the position of defending their efficiency, she said.
“You’re feeding the public frenzy of challenging other people’s data, if this becomes public,” she said. “This does absolutely nothing for resource adequacy.”
MISO said the pilot was authorized by FERC Order 787, which allows RTOs to share nonpublic information with gas operators. Previously, staff has said that the RTO is not attempting to influence generator behavior with the use of hourly profiles. (See MISO to Continue Gas-Electric Coordination Efforts in 2017.)
“MISO believes that sharing nonpublic, operational information with gas system operators can increase reliability for both industries,” the RTO said in a presentation. “Gas usage profiles, notably in severe operating conditions, will increase fuel assurance and reliability for gas-fired generators and will facilitate lines of communication with gas system operators.”
