Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
NOTE: There is no Members Committee meeting this month.
PJM Manuals (9:40-10:10)
Members will be asked to endorse the following proposed manual changes:
Manual 10: Pre-Scheduling Operations. Revisions reflect periodic review and clarify rules around maintenance outage recalls.
Members will be asked to endorse revisions to Manual 18: Capacity Market regarding the immediate replacement of capacity obligations. (See “Citigroup Wins Change on Capacity Resales,” PJM Markets and Reliability and Members Committees Briefs and “PJM, IMM Partner on Capacity-Replacement Revision” in this edition’s PJM Market Implementation Committee Briefs.)
Residual ARR Enhancements (10:40-10:55)
Members will be asked to endorse a rule change concerning residual auction revenue rights that was approved last week by the Market Implementation Committee. The changes, proposed by Exelon and Direct Energy, will require PJM to run another simultaneous feasibility test and pro rata distribution with all negatively valued bids removed. (See “Stakeholders Debate ARR Changes,” PJM Market Implementation Committee Briefs.)
FTR Undiversified Credit Adder (10:55-11:15)
Members will be asked to approve proposed revisions to the undiversified credit requirements for participation in financial transmissions rights auctions that were approved last week by the Market Implementation Committee. Under current rules, FTR credit requirements are calculated in two parts, one based on price and the adjusted historical values of individual FTRs, the second a portfolio-based “undiversified credit adder” applied to net counterflow portfolios — a process that some said caused clearing delays and credit uncertainty. The new rules eliminate the undiversified portfolio adder in exchange for increasing the adjustment factor in underlying credit calculations for historically counterflow paths from 10% to 25%.
Market Implementation Committee Charter (10:25-10:30)
Members will be asked to approve the updated MIC Charter, which eliminates references to “working groups.” (See “‘Working Groups’ Removed from MIC Charter,” PJM Market Implementation Committee Briefs.)
Summer resources in PJM’s market are approaching a tipping point. After April 2017, resources such as demand response and solar generation will effectively no longer be able to participate in PJM’s capacity market. As a result, they will no longer be able to earn the revenues that many rely on to stay in operation and to remain available during periods of peak customer demand.
This outcome is precipitated by PJM’s requirements that all resources meet strict winter performance requirements, or otherwise partner with winter-performing resources like wind generation, in order to bid into its next three-year forward capacity auction.
PJM has recognized this problem regarding retention of seasonal resources, and they have made moves to prevent the undesirable outcome. (See PJM to Seek FERC OK for Seasonal Capacity Proposal.) Under a recent proposal pending before FERC, PJM would make certain modifications to its summer-winter resource aggregation approach (ER17-367). However, past auctions have not yielded any viable participants in its resource aggregation program.
Musical Chairs
Even if all seasonal resources participated, aggregation can never fully solve the problem: Nearly 10,000 MW of summer-only DR and approximately 300 MW solar generation currently participate, in contrast to the 2,300 MW of available wind generation.[1] In the best-case scenario, with perfect aggregation, up to 8,000 MW of summer-performing resources are left with no winter aggregation partner. Like a game of musical chairs, when the music stops, some participants have no place to land. A mismatch exists, and the issue cannot be fully solved by aggregation.
The loss of summer resources will likely result in a significant cost impact to customers. PJM’s Independent Market Monitor estimated that without seasonal resources, costs could increase between $1 billion to $5 billion across PJM. Besides the customer impacts, the market will also lose some of its cleanest sources of generation. Unlike year-round DR resources that typically have backup generators, summer-only DR often relies on reductions in onsite consumption, such as by lowering air conditioning. Solar generators previously allowed to participate based on their higher summer output also will be excluded, absent pairing with scarce winter resources.
These cross-cutting issues motivated Rockland Electric to join environmental groups, including the Natural Resources Defense Council and the DR industry group Advanced Energy Management Alliance, in a joint protest at FERC. In separate responses, state agencies and other energy companies also expressed displeasure with PJM’s proposal and the loss of summer resources.
FERC Support Should not Waver
FERC has historically supported demand-side resource and renewable generation participation in wholesale markets. FERC proposed a rule in November that would open up access for smaller resources like batteries, which often have limited runtimes, to wholesale market revenues. In Orders 719 (2008) and 745 (2011), FERC enabled market participation by DR, while recognizing its benefits for creating just and reasonable rates. Through Order 764, FERC encouraged promulgation of market rules to better include variable energy resources. Allowing PJM to block access to these summer-only resources would undermine past efforts and effectively dismantle one of the country’s largest DR markets. Instead of allowing PJM’s untested approach, FERC should direct PJM to return to their summer, winter and annual resource comparability standards.
Shelly Lyser and Joel Yu are senior energy policy advisors for Rockland Electric. Rockland Electric, a wholly owned subsidiary of Orange and Rockland Utilities, which in turn is owned by Consolidated Edison Inc., is a transmission owner within PJM.
In a MISO first, the RTO has integrated a solar farm into its day-ahead and real-time markets.
North Star, a $180 million, 100-MW solar farm outside of Minneapolis, joined MISO’s wholesale markets on Dec. 16. Xcel Energy will purchase power generated by the facility in a 25-year deal that helps the utility meet its 1.5% solar energy requirement in Minnesota.
North Star Solar Farm | D.E. Shaw Renewable Investments
The RTO said months of planning and testing went into the project to ensure a “smooth integration of solar power into MISO’s day-ahead and real-time markets.” MISO tapped forecasting firm Energy and Meteo Systems — the same firm already handling the RTO’s wind forecasting — to forecast day-ahead solar.
“This project furthers the integration of renewable resources into our markets,” said Todd Ramey, MISO vice president of system operations.
MISO said that while several large-scale solar farms have been built in the footprint in the past few years, North Star is the largest in the Midwest, with more than 440,000 solar panels on 1,000 acres of former corn and soybean fields.
“Solar power from North Star is a key element in Xcel Energy’s plan to deliver more than 60% carbon-free energy for our customers by 2030,” said Chris Clark, president of Xcel Energy-Minnesota, North Dakota and South Dakota.
MISO filed the generator interconnection agreement between North Star and Xcel on Nov. 9 (ER17-329).
The solar facility is not allowed to exceed 100 MW. The project entered MISO’s interconnection queue as a variable energy resource last September. MISO mandated about $2.2 million in network upgrades, including grading, two new 115-kV breakers and four 115-kV switches as a condition of the agreement. Xcel spent about $260,000 for interconnection facilities.
Xcel and project partners D.E. Shaw Renewable Investments and Community Energy Solar reported completing the project in mid-October after six months of construction.
MISO said this year that it has about 1,700 MW of solar generation at various stages of its interconnection queue.
Following a dramatic all-night session, Michigan lawmakers Thursday approved legislation that increases the state’s renewable portfolio standard, preserves its limited retail choice and assigns state regulators to referee battles over net metering and capacity charges.
Governor Snyder on YouTube
Gov. Rick Snyder, who had been pushing revisions to the state energy policies since 2015, personally helped broker a compromise over retail choice, meeting with legislators overnight into early Thursday morning, then shaking hands on the Senate floor after its members voted 33-4 for the package (SB 437, SB438). The House approved the bills 79-28 and 76-31 earlier Thursday afternoon, the last day of the state’s two-year legislative session. (See Michigan Senate Increases RPS; Keeps 10% Retail Choice Cap.)
The first major change in Michigan energy policy since 2008, the legislation:
Sets a 15% renewable standard by 2021, up from the current 10%, while broadening the eligibility to include geothermal and pump storage;
Sets a nonbinding goal of meeting 35% of the state’s energy needs through renewables and energy efficiency by 2025;
Maintains the state’s 10% retail-choice cap;
Creates a “backup plan,” in case MISO’s proposed forward capacity auction for its competitive retail areas is rejected by FERC or proves too expensive;
Adds cost controls to the utilities’ required integrated resource plans; and
Allows utilities to offer competitive “value-added” services to supplement rate-base revenue.
Snyder took to his official YouTube channel Thursday to tout the bill, which he said would address concerns of a capacity shortfall. The state expects to lose 5,000 MW of coal-fired generation over the next seven years — pushing the state’s reserve margin down to 15%. Over the next 15 years, the state could lose 30% of its generation.
“What we’re in is a huge transition in how we get our energy,” Snyder said. “We’ve got a lot of aging coal plants that are beyond their useful life, and it’s not worth investing in them anymore. … We can transition to both natural gas and renewables and let the markets sort of define the balance between those two, so we’re moving away from an old energy source [where] we had to import all of this coal.”
Snyder also said he hoped the legislation would lead to more investment in solar power.
Capacity ‘Backup Plan’
To ensure the state has adequate capacity, the legislation requires a “much more robust” integrated resource planning process, said Greg Moore, legislative director for state Sen. Mike Nofs, one of the authors. Utilities will have to prove generation they build or buy is “the most reasonable and prudent” alternative. The IRPs, which must be filed every five years, will be expected to include provisions for energy efficiency, distributed generation and demand response, Moore said.
| Tradewind Energy
The bill also requires the Public Service Commission to conduct a contested hearing on whether a state capacity charge is “more cost-effective, reasonable and prudent” than MISO’s proposed forward capacity auction in meeting the RTO’s local clearing and the planning reserve margin requirements. If FERC fails to approve the forward auction by Sept. 30, 2017, the PSC will establish a “state reliability mechanism,” including a capacity charge. (See related article, MISO Forward Auction Filing Draws Protests.)
The commission would make separate findings for each utility service territory. If the commission implements a state capacity charge, it would remain in effect for at least four planning years unless that conflicts with the FERC ruling on MISO’s proposal.
MISO spokesman Jay Hermacinski said the RTO had no comment on the bill. “We really need to see what FERC’s going to do,” he said. “Once FERC’s made its decision then we’ll move forward. As we’ve done the last year and a half, we’ll be working with Michigan to come up with the best solution possible.”
The PSC also was directed to conduct a proceeding within one year on whether customers participating in net metering or distributed generation program should be charged a grid usage fee. It will consider both the costs net metering customers impose on the grid and the benefits they provide, said Moore.
Retail Choice Compromise
| DTE Energy
Some House Republicans had threatened to oppose the bill, fearing that a proposed capacity charge on competitive suppliers would kill the state’s retail-choice program. The state’s dominant utilities, DTE Energy and Consumers Energy, had sought the charge, accusing their competitors of being free riders.
“The question is how do you balance these all out, and I’m proud to say we got all of these groups largely to come to a strong agreement by finding some good middle ground,” Snyder said.
The legislation bars retail customers who return to their home utility after using an alternate supplier from returning to a competitor for six years. It also stipulates that if competitive suppliers lose customers and demand dips below the 10% threshold, the new, lower retail-choice percentage would become the new cap for six years. The competition program reportedly has a waiting list of about 11,000 customers.
Notwithstanding the cap, customers currently receiving all of their power from competitive suppliers would be able to increase their competitive loads at the existing or adjacent facilities.
Utilities would be allowed to supplement their rate-base revenues through “value-added” programs and services “if those programs or services do not harm the public interest by unduly restraining trade or competition in an unregulated market.”
Reaction
Consumers Energy Headquarters | Consumers Energy
DTE and Consumers both commended the bills’ passage.
DTE praised the increased renewable mandates and preservation of the state’s retail-choice market while adding reliability obligations. “It addresses these issues in a fair and constructive way and provides a framework for the state to plan for its own energy future,” DTE said in a statement.
Consumers said the “sound energy policy legislation [ensures] that our state has a comprehensive plan for ensuring electric reliability and affordable and sustainable energy going forward.”
The Michigan Environmental Council said the final bill was a “vast improvement” over earlier proposals that would have eliminated the RPS. “This deal will save millions of dollars a year for Michigan residents by continuing to eliminate energy waste and increasing investments in wind and solar power, which are the cheapest ways to produce electricity,” the group said.
The conservative Michigan Freedom Fund said the revised package “eliminates every anti-choice ‘poison pill’” in earlier versions of the legislation.
Although the bills ultimately won broad bipartisan support, not everyone was happy with the result. Republican Sen. Patrick Colbeck told Detroit station WXYZ that the bills were rushed through and that he did not support leaving electricity cost decisions in the hands of the PSC.
MISO’s proposed three-year forward auction in its retail-choice areas attracted more than 40 comments and protests, with critics calling the proposal costly and ill-conceived.
Executive Director of Market Services Jeff Bladen has said the proposal, which would take effect in the 2018/19 planning year, is designed to provide equally valued capacity from both merchant generators and regulated utilities (ER17-284). The comment period on the FERC filing closed last week; MISO expects a decision from the commission by March. (See MISO Files Forward Capacity Auction Plan with FERC.)
Among critics of the plan are MISO’s Market Monitor, which says the auction, with a sloped demand curve for competitive retail areas, will not accurately represent the marginal value of capacity. “The proposal is highly likely to result in unstable prices that are either too low to retain existing supply that is needed or excessively high, attracting new resources that are not needed,” Monitor David Patton said.
The Brattle Group’s sloped demand curve in red | The Brattle Group
In his protest, Patton included a proposal for a two-stage prompt auction for FERC consideration. Competitive retail supply would still use a sloped demand curve and regulated utilities would use a vertical demand curve.
Premature?
The Illinois Office of Attorney General objected to the bifurcation of the capacity market. “By separating Illinois from the rest of MISO through the use of a three-year forward auction, as opposed to the prompt auction applicable to the remaining 90% of MISO load, Illinois consumers would pay higher prices for capacity,” the office said.
Watchdog group Public Citizen said MISO did not have enough conversations with state lawmakers on their resource adequacy plans before making the filing, which he said will increase the cost to ratepayers. “This whole filing is a solution in search of a problem,” Tyson Slocum, the group’s energy program director, said in an interview. “That’s the whole problem with holding stakeholder meetings, it’s whoever shows up.”
“At a minimum, FERC should suspend issuing an order in this docket until the legislative actions of Illinois and Michigan to address long-term resource adequacy can be independently analyzed and incorporated into this docket,” Public Citizen wrote, referring to Illinois’ financial support for Exelon’s Clinton and Quad Cities nuclear plants and energy legislation approved by Michigan last week. (See Illinois Lawmakers Clear Nuke Subsidy and related story Michigan House Passes Energy Bill, Preserves RPS, 10% Retail Choice Cap.)
‘Blind Faith’
The Coalition of MISO Transmission Customers and the Illinois Industrial Energy Consumers filed a joint protest asking FERC to reject the filing because MISO did not fully include the results of The Brattle Group’s study, which the RTO relied on to justify the forward auction. The filing instead contained a MISO description of the study, demand curve diagrams, presentations made to MISO stakeholders by Brattle and testimony from three Brattle employees.
“The commission should not accept, on blind faith, that the Brattle study appropriately supports MISO’s endeavors,” the groups said. They also challenged Brattle’s analysis as biased. Alliant Energy and others challenged MISO’s reliance on the results of the OMS/MISO survey, which forecasts generation shortfalls in 2018. The company said the survey is not a “complete reflection of the future capacity needs in the MISO region.”
Results of the 2016 MISO-OMS Survey | OMS, MISO
A group of transmission-dependent utilities in the Midwest — Madison Gas and Electric, Missouri Joint Municipal Electric Utility Commission, Midwest Municipal Transmission Group, Missouri River Energy Services and WPPI Energy — argued the proposal is “fraught with inconsistencies, errors and ambiguities” that could cause the provisions of the forward market to bleed into noncompetitive areas. The group asked FERC to reject it.
Interference
Power marketer Direct Energy, which offers competitive natural gas plans for Michigan ratepayers in Consumers Energy and DTE Energy territory, objected to MISO’s Tariff revisions to allow retail-choice states to opt out of capacity provisions via the auction design’s prevailing state compensation mechanism. The company is challenging the filing on the basis it “impermissibly” interferes with wholesale markets.
Ron Carrier, Direct Energy’s director of government and regulatory affairs, said he isn’t sure if the limited amount of participating generation and load from retail choice areas would make the forward auction economic, although he said forward auctions in general “allow some price certainty into the future.”
“Our main concern is the state shouldn’t be granted authority over something FERC should have authority over,” Carrier said.
MISO Transmission Owners said they had no opinion on the filing, but they asked FERC to make sure the RTO does not intrude on state jurisdiction over resource adequacy. They also asked FERC to require MISO to give annual reports that analyze the impact of the forward auction on the entire footprint for the next three years.
The Organization of MISO States also argued for protecting state jurisdiction, but the group took a step further, asking FERC to reaffirm the stance it took in a 2012 order that capacity markets are not necessary in vertically integrated areas (ER11-4081-001). “The [competitive retail solution] should not be viewed as the default means to maintain [resource adequacy] within retail-choice areas. It is imperative that state regulators maintain maximum flexibility and authority over the resource adequacy decisions within their jurisdiction,” OMS wrote.
AUSTIN, Texas — ERCOT celebrated a trio of memorable anniversaries Tuesday by getting part of the band back together for its Annual Membership Meeting.
ERCOT, which became the first ISO in the U.S. 20 years ago, also marked its 15th anniversary as the single control area for the state’s competitive market and the 75th anniversary of the Texas Interconnected System, when the state’s utilities banded together to ship power to the shipyards and refineries on the Gulf Coast during World War II.
“We remain the only independent, state-controlled system operator,” ERCOT CEO Bill Magness told the membership, “and we like it that way.”
To mark the occasion, ERCOT unveiled a historical video and brought back its first Board of Directors chairman, former Oncor president Mike Greene, to introduce one of the primary architects of the state’s electric restructuring bill as the meeting’s guest speaker. Steve Wolens, a retired 12-term Democratic state representative, worked with Republican State Sen. David Sibley to push Senate Bill 7 through the Texas Legislature in 1999 against only four opposing votes.
Greene name-dropped former Texas PUC commissioner and current ERCOT Director Judy Walsh, former FERC and PUC commissioner Pat Wood and others from the past before eventually introducing Wolens.
“My role has been reversed. I’m standing at the microphone, and Steve is in the audience wondering what I’m going to say,” Greene said, before taking a pause. “I’m actually starting to enjoy this.”
“It’s an honor to be back,” said Wolens, pegged by Texas Monthly in 1999 as the “Intellectual Gladiator” for his legislative work. The magazine noted Wolens “produced an electricity deregulation bill that won the support of consumers, environmentalists and utilities.” When the bill passed, Wolens’ colleagues honored him with a standing ovation.
Wolens, who also led a push to reform ethics laws before retiring from the Legislature in 2005, was recently named by Texas House Speaker Joe Straus to serve on the Texas Ethics Commission. His term will last until November 2019.
Recounting SB7’s history, Wolens said “there was no reason to restructure in the 90s,” given Texas had the lowest electric rates in the country. However, the state also had some of the highest bills ($1,064 annually for the average residential customer, he said) and a reserve margin that was predicted to drop below 8% by 2004.
“And here we were in Texas, boasting about the state and boasting about our growth.”
Wolens said the inability to get energy companies to invest and Ohio-based American Electric Power’s announcement that it would acquire Dallas-based Central and South West Corp. in 1997 gave the restructuring legislation a boost.
“We had to bring more certainty, more reliability to the market,” he said. “Our goal was to reduce the risk to private investment and do whatever we could to keep the local companies we had.”
The key to SB7 was its price-to-beat (PTB) measure, Wolens said. The bill required incumbent utilities to take a 6% rate cut and hold that for three years, or until they lost 40% of their previously regulated market share.
This was to discourage what Texas had seen in other restructured markets, Wolens said. “We had seen it all,” he said, referring to trucking, banking and airline deregulation. “Once you deregulate, the incumbent in that particular industry, the powerful player, cuts rates and drives everyone else out of business. The three years allowed new competitors to come in.”
And that’s exactly what happened in the ERCOT market. Wolens noted nearly 200 residential retail electric providers currently operate in the state, offering in his estimation some 2,000 plans to choose from. The ERCOT market will record its lowest average energy prices this year ($24.64/MWh) since the market opened ($25.64/MWh in 2002).
“The PTB was the DNA of the entire bill,” Wolens said.
SB7 and the ensuing $7 billion Competitive Renewable Energy Zone transmission project, which connected windy West Texas with the growing urban population centers to the east, has given the state almost 18,000 MW of installed wind capacity. If the Lone Star State were its own country, it would rank sixth in the world in wind capacity.
The Texas market is so strong, Wolens said, it will survive a future that may include the country’s withdrawal from the Paris Agreement, the loss of wind and solar tax credits and “installing a climate denier” at EPA.
“All those issues aside, it’s not going to make a difference because the market is vibrant,” he said. “It’s exactly what we hoped for in 1999.”
Magness Celebrates ERCOT’s Achievements
Magness listed ERCOT’s 2016 achievements before the luncheon began, including maintaining a reliable system and efficient market, upgrading the Energy Management System, revising the criteria for reliability-must-run studies, completing transmission improvements in the Rio Grande Valley and integrating wind generation.
The ERCOT market generated more than 15,000 MW of wind energy for the first time in 2016, setting a new record of 15,033 MW in November. It also recorded three new marks for wind penetration during the year, topping out at 48.28% of load in March.
Magness credited stakeholders’ collaboration with staff and their forward thinking with making the records possible.
“We’ve always said if we can see it, we can integrate it,” he said. “When we hit 15,000 MW of wind and high penetration levels, people asked, ‘How do you do that? How is that possible?’ It’s possible because in ERCOT, when those things start to happen, we talk about it. That’s the value of thinking ahead while still in real time.”
ERCOT also set a new system peak (71,110 MW on Aug. 11), two monthly demand highs (during a warmer-than-normal September and October) and a new weekend peak (Aug. 7). The ISO’s annual Capacity, Demand and Reserve report released Thursday foresees demand rising to more than 77,000 MW by the summer of 2021. (See related story, ERCOT Sees Increased Load Growth, Shrinking Margins.)
Increasing Demand Boosts Finances
The high demand in the fall means the ISO should go into 2017 — the second year of its two-year spending plan — with net revenues as much as $13 million above budget. Also helping ERCOT’s finances are savings in resource management costs (primarily staffing management and project work), expected to come in $3.9 million under budget, and computer hardware purchases, at $1.9 million under budget.
“We challenged ourselves as a management team to maintaining some flexibility for ourselves, going into [the] second year,” Magness said. “We’re committed to keeping a flat [administrative] fee for at least two years. Keeping that budget discipline is going to be really important in maintaining that. One year in, we feel like we’re in a pretty good place.”
Magness also said ERCOT’s “technology refresh” to update aging computer technology is well underway. The four-year project began in 2015 and is forecast to come in at or under its $48 million budget. Magness said 60% of the contracts are locked in place, with 21% of the hardware already deployed.
Board Passes Transmission Planning Change
The board easily passed the only contested revision request before it, a planning guide change revising the criteria used to determine the need for new transmission projects that faced some pushback at the Technical Advisory Committee earlier this month. (See ERCOT Addresses Transmission Planning Challenges with New Rule.)
Valero Services’ Jack Durland, representing the Industrial Consumer sector, cast the lone dissenting vote. He questioned the planning guide revision request’s (PGRR) “bounded higher of” load forecast methodology, in which ERCOT will compare its load forecast with the summed bus-level forecast for each weather zone, and the need for two additional staffers to work on the planning process.
“Does one size fit all the [ERCOT] regions?” Durland asked. “If it doesn’t, we’ll end up with constraints, specifically in Houston. We’d like to see maybe some backcasting to understand this higher boundary methodology actually does fit most scenarios.”
PGRR042 defines considerations for selecting the most appropriate demand forecast in planning studies and how to model certain generation resources, such as mothballed units or those that can be also be connected outside the ERCOT region, in planning cases. It also describes how to incorporate new generation units in sensitivity analyses when they have interconnection agreements but have not met all the requirements to be included in transmission planning studies.
Warren Lasher, ERCOT’s senior director of system planning, told the board the ISO will “grey box” the PGRR’s language before formally codifying it for 2018. In the meantime, he promised staff would work closely with stakeholders throughout next year “to ensure we have an appropriate mechanism to make sure we have adequate transmission.”
“We have been having discussions with stakeholders about doing backcasts for the forecasts in the planning working groups,” Lasher said, “and we will continue to have those discussions … to make sure that the needs of customers, especially in the Houston region, and other regions of the state are met.”
“I can tell you with confidence that we can move around folks,” Magness said, addressing the staff additions. “Two [full-time employees], we can handle.”
Magness reminded stakeholders that PGRR042 came from a Public Utility Commission of Texas request to re-evaluate ERCOT’s planning process, part of the commission’s approval order for the Houston Import Project, a $590 million initiative due to be completed by summer 2018.
“This planning guide became the vehicle for the analysis,” he said. “Our folks feel comfortable they have sufficient flexibility and options for making sure the change works. It was a successful accommodation … of something we could work with, and we felt like folks in the market could work with, as well.”
New Board, TAC Members Approved
The ERCOT board approved Calpine’s Randy Jones and Source Power & Gas’ John Werner as new members of the board for 2017. The two, who served as alternates last year, will represent the Independent Generator and Independent Retail Electric Provider segments, respectively.
Jones is switching places with E.ON Climate and Renewables’ Kevin Gresham, while Werner replaces Direct Energy’s Read Comstock.
The board has yet to fill the unaffiliated position vacated by Jorge Bermudez, who resigned from the board in October when his pending marriage created a conflict of interest. (See “ERCOT’s Bermudez Resigns from Board Position,” ERCOT Briefs.)
“We were distressed to find out you love someone more than us,” joked Board Chair Craven Crowell, before presenting Bermudez with a resolution honoring his service.
The board also approved the Lower Colorado River Authority’s John Dumas and Golden Spread Electric’s Mike Wise (Cooperatives), SESCO’s David Hastings (Independent Power Marketers) and Direct Energy’s Sandra Morris and Noble Americas Energy Solution’s Clint Sandidge (Independent Retail Electric Providers) as new TAC members.
Ancillary Service Changes, NPRRs Sail Through
The directors unanimously approved “very minimal” changes to the minimum ancillary service requirements, after two years of more substantial changes.
Staff limited its changes to regulation service. It proposed removing the exhaustion rate feedback metric from the regulation-procurement analysis, estimating five-minute net load variability by including solar generation and making annual updates to the 2013 General Electric study’s tables reflecting incremental installed wind generation.
The board also unanimously approved a clean Statement on Standards for Attestation Engagements (SSAE) No. 16 audit report, modifications to forms ensuring the credit worthiness of market participants and five changes to the 2016 list of key performance indicators used to drive organizational performance.
The board consent agenda, which passed unanimously, listed eight nodal protocol revision requests (NPRRs):
NPRR773: Broadens the scope of acceptable letter of credit issuers, allowing electric cooperatives to post letters from the National Rural Utilities Cooperative Finance Corp. with ERCOT.
NPRR783: Revises a requirement for an independent audit to confirm the consistency of ERCOT operations models. The change is to comply with NERC reliability standard MOD-033-1 requiring a documented data-validation process for power flow and dynamic models.
NPRR790: Adds phase angle equipment limitations to real-time monitoring, real-time assessments and operational planning analysis, as required by NERC standards. ERCOT will collect this information through the network operations modeling process.
NPRR791: Clarifies the initial estimated liability (IEL) description to specify that it is based on estimated sales between qualified scheduling entities; restores the IEL for traders (inadvertently omitted from NPRR741) and corrects errors to the minimum-current exposure formula mistakenly overwritten by NPRR743.
NPRR792: Aligns the nodal protocols with NERC’s definition for special protection system (SPS) and uses “remedial action scheme” and “automatic mitigation plan” in place of SPS for consistency purposes, when applicable. The approval resulted in the TAC conducting an email vote on a related nodal operating guide request, NOGRR164, which was approved Thursday, 21-0.
NPRR797: Creates a new report and display for the actual system load by forecast zone, similar to the capability for weather zones.
NPRR801: Revises the physical responsive capability (PRC) calculation to include all load resources and align operating reserve demand curve (ORDC) reserves with the PRC change. It also aligns the ancillary service imbalance settlement with the change to the ORDC reserves.
NPRR803: Removes un-codified language from NPRR439, which was approved four years ago to allow counterparties to increase their credit limit for the day-ahead market’s current day.
The Public Utility Commission of Texas wrapped up its 2016 open meeting schedule Friday by approving a rulemaking on interconnection agreements (IAs) for distributed generation and reports on electric market competition and alternative ratemaking mechanisms.
The distributed generation order allows the end-use DG customer to either be a party to the agreement or the “non-utility” party as the owner of the facility, the facility’s premises or the produced energy (No. 45078). The commissioners said they would have jurisdiction over IAs, but not over “any disputes between an end-use customer and a non-utility signatory to the IA.”
| ERCOT
Chairman Donna Nelson dissented from the order. She had expressed concerns last month over the PUC’s inability to help solar energy customers seeking redress from the commission over potential “bad actors.”
2017 Competition Report
The PUC approved its “2017 Report on the Scope of Competition in Electric Markets in Texas” (No. 45635), accepting Commissioner Ken Anderson’s suggestion that the report repeat previous recommendations to the Texas Legislature calling for:
The repeal of state law establishing natural gas as “the preferential fuel” for electricity generation and creating natural gas energy trading credits. “Because natural gas-fueled facilities have been the most commonly built new generation in Texas for many years and are expected to continue to be, there is no need to establish incentives for natural gas generation,” the report says.
The repeal of state law requiring the installation of 5,880 MW of renewable energy by 2015, a mandate that was met in 2008.
Authorization for the PUC to issue advisory opinions on electric industry issues. “Providing clarification to a company concerning issues such as the purchase of assets or the acquisition of another company could allow it to avoid expensive regulatory proceedings, without impairing the commission’s authority,” the report says.
Authorization for the PUC to use outside consultants, auditors, engineers or attorneys to represent the state before ERCOT, as it is currently permitted to do in FERC proceedings.
| ERCOT
The commission also approved its report on alternative ratemaking mechanisms, which concludes that the current ratemaking system is not “in need of major revision” and that periodic rate proceedings using “streamlined recovery mechanisms” is “an efficient and effective way to ensure that electric rates are just and reasonable” (No. 46046).
The report does suggest the Legislature address concerns about vertically integrated utilities operating outside the ERCOT service area, whose key financial metrics “have lagged in comparison to those of the ERCOT utility companies,” with reported rates of return consistently falling below PUC-authorized levels. The report says the utilities’ returns have been hampered by “regulatory lag” in recovering capital investments.
Both reports will be sent to the Legislature, which convenes Jan. 10.
SPP and MISO continue to study seven potential joint transmission projects across their seam, but much of their focus is now turning to developing the 2017 joint study by next April.
Staff from the two RTOs told their Interregional Planning Stakeholder Advisory Committee on Friday that they have already begun to put together a work plan that includes a study scope, timeline and Tariff and joint operating agreement changes needed to accommodate the study.
RTO staffers met in October at MISO’s Louisiana offices to lay out a high-level framework for the study, which would end in 2019. Staff hope to improve coordination of their regional processes and sharing of regional planning assumptions.
“As we develop our regional plans individually, we would start developing regional candidate projects,” said MISO’s Davey Lopez, advisor of planning coordination and strategy. “Both parties agreed we want to plan for the best value, which may not be the cheapest solution.”
Lopez and his counterpart, SPP Interregional Coordinator Adam Bell, said their boards would be able to evaluate the regional projects and interregional projects on the same timeline, eliminating one of the stakeholder complaints in recent years.
“One of major hurdles we have is the timing of the regional processes,” Bell said. “Both sets of stakeholders will be able to look at regional and interregional plans at the same time, and pick the best project. One is not winning out by virtue of finishing first.”
| MISO-SPP IPSAC
Lopez told the IPSAC that the 2017 study will begin as the 2016 coordinated study process ends, using the latter’s study results as an input. “We’d like to ramp it up in April 2017, hit the ground running and jump right into another study,” he said.
The 2016 analysis has resulted in seven potential projects, primarily in the Dakotas and along the Kansas-Missouri border. Lopez said the list may be reduced further but that it is “good information for the 2017 study.”
Three of the projects would solve market-to-market flowgates, which have resulted in payments from MISO to SPP totaling $2.75 million.
Nine entities have submitted 32 solution ideas to address the project needs posted in October. Several of the solutions were duplicates of, or similar to, others.
Final study results will be shared with the IPSAC during its next meeting, tentatively scheduled for February.
Competitive Tx Process Task Force Suggests Criteria Change
The Competitive Transmission Process Task Force completed its review of the documents to be used by transmission developers bidding on projects through SPP’s Order 1000 competitive process.
Stakeholders determined that the inflation rate (2.5%), discount rate (8%) and operations and maintenance escalation rates should be prescribed by SPP in its solicitation.
Duke Energy’s Bob Burner proposed the group use a “pass-fail” grading system rather than point-scoring for certain qualitative items evaluated by the industry expert panel (IEP).
Staff noted the Tariff language gives the IEP sole discretion in determining how it scores competitive proposals but agreed to recommend to the panel which items should fall into the pass-fail category. Staff will draft a revision request that would remove certain pass-fail items from the solicitation process. Points allotted to the scoring categories would not be impacted.
The task force will meet again Jan. 9, in preparation for the Markets and Operations Policy Committee meeting two weeks later.
Gas-Electric Coordination Report Filed with FERC
SPP on Friday filed with FERC its first informational report on the RTO’s efforts to coordinate gas and electric scheduling practices. Staff shared a draft of the report two weeks ago with the Gas-Electric Coordination Task Force. (See “SPP to Deliver Positive Report to FERC on Gas-Scheduling Practices,” SPP Briefs.)
The report was filed to comply with FERC Order 809, which required RTOs to improve the alignment of their market schedules with those of interstate gas pipelines (RM14-2). SPP’s changes took effect Sept. 30.
SPP Sets New Winter Peak Mark
SPP set a new winter demand peak earlier this month, hitting 37,780 MW at 7:21 a.m. Dec. 9. The mark broke the previous record of 37,412 MW set Jan. 18.
FERC on Thursday declined to grant a solar developer’s petition to enforce the Public Utility Regulatory Policies Act in Montana, where state regulators in June suspended a utility’s tariff for qualifying solar facilities above 100 kW (EL17-5).
As a result, solar developer FLS Energy can sue the Montana PSC or NorthWestern Energy in federal court, if it chooses.
FLS Solar’s Fairmont Solar Farm in Fairmont, NC | FLS Solar
But FERC did find that the Montana Public Service Commission violated PURPA by requiring that qualifying facilities have power purchase agreements and interconnection agreements with utilities to form a legally enforceable obligation.
The Montana PSC voted 3-2 to suspend NorthWestern’s tariff, finding that the avoided cost rate the utility was required to pay QFs was too high. The PSC grandfathered in facilities that had completed their agreements prior to the date of the order, June 16.
In its complaint filed in October, FLS said it had completed PPAs, but not interconnection agreements, for 14 QFs in the state. It accused NorthWestern of slow-walking the interconnection process while it lobbied the PSC for the tariff suspension.
As a result of the suspension, the North Carolina-based company said it stands to lose $750,000, as it would have to negotiate new PPAs with NorthWestern, likely at a lower rate.
Under PURPA, utilities are obligated to purchase electricity from QFs, but each state can determine when a legally enforceable obligation begins, as long it does not conflict with FERC’s regulations.
“We find that, just as requiring a QF to have a utility-executed contract, such as a PPA, in order to have a legally enforceable obligation is inconsistent with PURPA and our regulations, requiring a QF to tender an executed interconnection agreement is equally inconsistent with PURPA and our regulations,” FERC said. “Such a requirement allows the utility to control whether and when a legally enforceable obligation exists — e.g., by delaying the facilities study or by delaying the tendering by the utility to the QF of an executable interconnection agreement.”
FERC’s order did not comment on the merits of the PSC’s suspension itself, which FLS had also requested. The commission last month tossed out the same complaint by solar advocates, saying only QFs can seek PURPA enforcement. (See FERC Rejects Complaint on Montana Solar; 2nd Case Pending.)
In a footnote, however, FERC said, “When a state commission believes that a previously determined avoided cost rate is no longer an accurate measure of a utility’s avoided costs, the appropriate response is not to establish a standard for a legally enforceable obligation that is inconsistent with PURPA and the commission’s regulations under PURPA, but instead to determine a new avoided cost rate that better reflects the utility’s avoided costs.”
“This is a great win for our company and the QF community,” Steven Levitas, vice president of business affairs and general counsel for FLS, said in an interview. “We were confident that the Montana commission’s [legally enforceable obligation] was inconsistent with PURPA.”
Levitas said that the company hopes the PSC will change the standard to comply with PURPA. Otherwise, he said, the company is prepared to take it to court.
FERC did not address FLS’s accusation that NorthWestern violated interconnection procedures, saying that, as a Federal Power Act matter, it was beyond the scope of the complaint.
MISO engineer Adam Solomon told the Planning Subcommittee Dec. 13 that while it is possible to make joint powerflow and economic models, they would not be based on a set of common assumptions. “We think we can make assumptions from both MISO and PJM using separate sensitivities,” Solomon said during a Dec. 13 Planning Subcommittee meeting.
In an April 21 order, FERC directed MISO and PJM to explore with stakeholders the possibility of a joint model that uses identical model assumptions and criteria for regional transmission planning processes (EL13-88).
MISO has maintained that a joint model would be difficult to accomplish, as it studies two, five and 10 years into the future, while PJM studies five, seven and eight years ahead. In addition, MISO uses local balancing areas for dispatch, while PJM uses a single balancing area. PJM also does not forecast generation retirements, while MISO includes forecasted generation retirements in its futures modeling.
The RTOs’ Oct. 25 informational filing to FERC detailed their reasoning as to why a single set of assumptions was infeasible. The RTOs told FERC that “most stakeholders agree with the RTOs’ position that requiring the RTOs to adopt the same assumptions and criteria when conducting regional transmission planning would create significant challenges, including substantial revisions to each RTO’s robust regional planning processes and cost allocation methodologies.”
But Northern Indiana Public Service Co., whose complaint prompted the FERC order, said in comments to MISO that the two RTOs need a joint model because their different study processes lead to projects being categorized inconsistently (e.g., reliability, public policy or economic). “However, tests of NERC reliability thermal or voltage violations have less disparity between RTOs. Reliability models typically have similar topology, base resource modeling and demand assumptions,” the utility said.
In a Nov. 15 filing with FERC, NIPSCO accused the RTOs’ of ignoring the commission’s directives. “The pattern of behavior shown by the RTOs … demonstrates that [they] are committed to interpreting the April 21 order as empowering the RTOs to eliminate the Coordinated System Plan Study for interregional planning, which is plainly contrary to the spirit, if not the letter, of the commission’s orders,” NIPSCO said.
At the Dec. 14 Planning Advisory Committee meeting, Adam McKinnie, chief utility economist for the Missouri Public Service Commission, asked MISO to create a common interregional model before it embarks on more studies, such as the MISO-SPP joint study running through the first quarter of 2017. (See MISO-SPP Study Scope Finalized; Stakeholders Doubtful Projects will Result.)
Ameren said MISO and PJM should use the same base models for system load conditions, such as light load, summer shoulder peak, winter peak and summer peak conditions. Other members, including Great River Energy, ITC Holdings, WPPI Energy and American Transmission Co. said they understood MISO’s reluctance to adopt identical assumptions.
Retirement Risk, Deliverability Measured for MTEP 17
MISO’s deliverability analysis for the 2017 Transmission Expansion Plan will identify transmission constraints and possible violations on a five- and 10-year horizon, MISO engineer Carlos Bandak said.
Bandak said the deliverability analysis will determine whether groups of generators in an area can operate at maximum capability without being “bottled-up.” The information is used in granting or denying network resource interconnection service (NRIS).
After stakeholders expressed concerns that MISO would use historical limits for the deliverability analysis, Bandak reassured stakeholders that the RTO each year produces fresh results and does not test values from previous years, although it will not test above already-granted NRIS levels for existing generators.
Stakeholders argued that MISO might test above the approved NRIS level to a generator’s potential capability.
“We’re not going to use the deliverability study to grant incremental capability. That would be too complicated,” said MISO Director of Planning Jeff Webb, adding that the generator interconnection queue is the arena where owners should go if they want to be granted more generating capability.
“All we’re doing here is making sure that generators continue to be deliverable through their interconnection service. There’s nothing really new or strange here,” Webb said.
MISO also will incorporate a retirement sensitivity analysis in MTEP 17’s annual reliability assessment.
MISO will perform 10-year-out sensitivity analyses for age-based retirements modeled in MTEP 17’s “existing fleet” future. By 2027, all coal units 65 years or older and all gas and oil units 55 years or older will be assumed to have been retired.
In 10 years, the MISO footprint will contain 6.4 GW of at-risk coal generation and 10.7 GW of susceptible natural gas and oil generation. The RTO places the current average age of its coal fleet at 38 years and its natural gas and oil fleet at 22 years.
MISO engineer Anton Salib said the RTO would build models until March and test them through May, with preliminary findings released in June. A full report is expected by September.
Ginger Hodge of Customized Energy Solutions asked if results would be included in the MTEP 17 Market Congestion Planning Study. Salib said the findings may inform the study, but information from a variety of analyses would also be used.
By the end of 2016, MISO expects $2 billion more of MTEP 15’s transmission projects to be in-service. Project candidates for MTEP 17 are to be submitted by Sept. 15, 2017. Solomon said the overall scope of MTEP 17 studies will be completed by the end of this month.
In response to stakeholder feedback on the MTEP 17 scope, MISO told the Dec. 14’s Planning Advisory Committee it would consider removing independent load forecasting from the MTEP process because it is not governed by the RTO’s business practices. Purdue University’s State Utility Forecasting Group currently estimates MISO’s power demand. The PAC could weigh in on the future of the forecasting after the new year.
