PHILADELPHIA — Stakeholders agree PJM’s future likely involves carbon pricing, but they lack consensus on how the RTO will manage as many as 13 different state policies within the wholesale market over the next decade.
Stu Bresler, PJM’s senior vice president of operations and markets, said Wednesday that the RTO views its role in implementing external pricing as advisory and supplemental to state-enacted rules. Given the breadth of PJM’s territory, however, it’s not clear what such a system would look like or how varied it might be.
“I don’t think PJM has the authority to implement a carbon price,” Bresler said. “If state policymakers decide to price carbon in their jurisdiction, we could make it relatively simple as long as it’s systemwide and still achievable — but more complicated — if it’s only some states.”
Bresler’s comments came during Raab Associates’ Energy Policy Roundtable in the PJM Footprint, where panelists discussed what the PJM market might look like in 2030. They talked about their respective priorities on ensuring grid reliability, fuel security and resilience, and anticipating future technologies and integrating more renewable resources. Carbon pricing, however, dominated the conversation.
“We’ve reached an equilibrium where the natural gas units are no longer going to push coal retirements, and carbon emissions will increase,” said Ralph Izzo, CEO of Public Service Enterprise Group. “PJM must put in an external price marker … or it will become an irrelevant wholesale power market.”
In New Jersey, home to PSEG headquarters, the Board of Public Utilities on April 18 approved $300 million worth of zero-emission credits for its three nuclear reactors that struggle to profit at low wholesale prices set by polluting fossil fuels. Nuclear power provides more than a third of New Jersey’s emissions-free energy and remains vital to achieving the state’s ambitious clean energy goals, regulators said. (See NJ Approves $300M ZECs for Salem, Hope Creek Nukes.)
Pennsylvania lawmakers likewise continue talks on a pair of bills that would create the largest nuclear subsidy program in the country, while legislatures in Illinois, New York and Connecticut have approved their own nuclear subsidies. Executives at Exelon and FirstEnergy say the programs prevent premature retirements of reactors that provide clean, reliable energy 24/7, 365 days a year, despite a market design that doesn’t appropriately reimburse them for such service. (See Nuke Talks Continue in Pa. Assembly.)
“Many states probably have many questions beyond just, ‘What will the cost on carbon be?’ or ‘What happens to all the revenues?’” said Morris Schreim, senior adviser of the Maryland Public Service Commission on issues relating to PJM and FERC. “These could include, ‘Will our environmental policies be overtaken by for-profit utilities and other entities?’ Or, ‘Who will have jurisdiction over the air we breathe?’ Keep in mind, [Regional Greenhouse Gas Initiative] states never gave up their rights to a regional entity. Success in 2030 will be ensured if the answers to these questions stay within the realm of state policymakers.”
Kristin Munsch, deputy director of the Illinois Citizens Utility Board and president of the Consumer Advocates of PJM States, encouraged the RTO to take a more direct role rather than leaving it all to a “one-size-fits-all market design.”
“What I’d like to see PJM do is move from accommodating state policy to enabling it,” she said. “PJM in 2030 absolutely needs to think about how you enable this market.”
Izzo said an effective carbon price would drive onshore wind development and transmission expansion, while reducing the need for nuclear subsidies and crushing demand for rooftop solar — the most expensive of all renewable resource technologies, he said. More fossil fuel plants would likely retire, Bresler added.
PJM’s Markets and Reliability Committee endorsed a problem statement and issue charge on Thursday about implementing carbon pricing in the RTO. The effort will likely take more than two years, and it will consider ways to balance the concerns of states uninterested in enacting the policy. (See PJM Members Welcome Carbon Pricing Talks.)
“Dialogue is always important,” Schreim said of the effort. “An open stakeholder process could identify ways to provide value in meeting consumers’ needs that have never been considered before.”
A NERC standards drafting team (SDT) has opened a final ballot on the elimination of all or parts of 18 reliability standards as Phase 1 of the organization’s standards efficiency review (SER) nears its conclusion.
Ballot pool members will have until May 2 to vote on the changes: the withdrawal of one proposed reliability standard, the complete retirement of 10 standards and the elimination of certain requirements for seven standards. (See chart.)
All the proposed retirements received 88 to 99% support in segment-weighted voting in the initial ballot that closed April 12. “They all passed at pretty high percentages,” observed NERC’s Laura Anderson, standards developer for the SDT at a team meeting April 17.
NERC’s ballot body, representing its 10 industry segments, currently has 525 members.
Proposed retirements that clear a two-thirds segment-weighted threshold on the final ballot will proceed to final approval by NERC’s Board of Trustees, likely at the board’s May meeting. Votes from the initial ballot are automatically included in the final ballot, although voters can change their positions.
Pruning the Rules
The Standards Efficiency Review Retirements effort (Project 2018-03) was created to take a second look at the rules that have been created since FERC certified NERC as the electric reliability organization (ERO) in 2006.
Three teams — representing real-time operations, long-term planning, and operations planning — identified for elimination requirements that were duplicative, obsolete or that were administrative and did not provide reliability benefits. Many of the standards to be retired relate to commercial business practices governed by the North American Energy Standards Board (NAESB) Wholesale Electric Quadrant (WEQ).
NERC last month closed the comment period on Phase 2 of the SER project. The phase involves considering changes in six areas of the organization’s operations and planning (O&P) and critical infrastructure protection (CIP) standards, including evidence retention time frames, moving requirements to guidance, simplifying training requirements and consolidating data exchange requirements. (See “Chair Urges Comments on Standards Efficiency Review,” NERC Standards Committee Briefs: March 20, 2019.)
The comments on the Phase 1 recommendations indicated how much the industry has changed since NERC became the ERO and gained enforcement authority.
For example, Black Hills Corp. said requirements 16 and 17 of standard TOP-001-4 provide no reliability benefit. The rule is intended to ensure prompt action to prevent or mitigate instability, uncontrolled separation or cascading outages.
The requirements direct transmission operators and balancing authorities to provide their system operators with authority to approve planned outages of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels.
The requirements “don’t even align with most, if not all, standard business processes,” Black Hills’ Maryanne Darling-Reich said. “The outage coordinator, [supervisory control and data acquisition emergency management system], IT networking and communications departments determine the impacts of all ‘planned’ outages of telemetry equipment. Most system operators do not even have the technical knowledge to make a substantiated decision to delay or postpone this work.”
MOD Standards
Eight of the 18 standards proposed for retirement were from NERC’s modeling (MOD) family of rules. The SDT proposed the elimination of seven of the MOD standards, including those on calculations of capacity benefit margins, transmission reliability margins and transfer capability — requirements incorporated in NAESB standards.
The standard authorization request (SAR) that initiated the SER project said that available transfer capability (ATC) and available flowgate capability (AFC) are “commercially based values used to facilitate a market for unused transmission capacity in an open access environment and that the values do not directly control the operation of the [bulk power system]. … [Transmission operators] are ultimately responsible for operating the grid in a reliable manner consistent with system operating limits, not ATC/AFC values.”
The team also proposed not implementing MOD-001-2, which has been awaiting FERC approval since February 2014 (RM14-7). It was intended to ensure calculations of available transmission system capability support reliability and that the methodology and data behind the calculations are disclosed to applicable registered entities.
The SAR said MOD-001-2 was not needed because although ATC and AFC values can influence real-time conditions, other standards, including subsequent improvements to TOP rules, ensure that real-time operations observe system operation limits. The “commercially based values and market related issues [regarding ATC/AFC] should not be addressed through NERC reliability standards,” it said.
Despite the high level of support for the retirements, there were some forceful dissents.
Duke Energy, for example, said it could not support the elimination of the seven existing MOD standards if MOD-001-2 is withdrawn.
“We disagree with the commercial-based focus that the drafting team took in the technical rationale document,” Duke’s Kim Thomas wrote. “While these MOD standards (and ATC calculation) may have some commercial-based elements to them, they also put in place valuable boundaries that help promote consistency in how the industry calculates these values. Removing these boundaries does not promote reliability for the bulk electric system and introduces additional burden to the real-time system operator.”
Southern Co. took a similar position, saying that transferring the seven MOD standards to NAESB without enacting MOD-001-2 would upset the “appropriate balance of addressing reliability-related concerns, while incorporating any market related issues.
“Simply stating that ATC/AFC calculations are primarily commercially focused elements and that there are mechanisms in place to address reliability in real time is an oversimplification of the ATC/AFC concept,” Southern’s Marsha Morgan wrote. “Inaccurately modeling and assessing transfer capability which considers real physical transmission limits on both the host and neighboring systems can create extremely complicated situations in real time that can unduly burden system operators.”
PJM, which was neutral on the elimination of MOD-001-2, supported the proposal to transfer the other MOD standards to NAESB, saying “reliability components of congestion management are handled amongst Eastern Interconnect parties through various established coordination processes.”
It warned against additional revisions to the NAESB WEQ rules, “especially those driven by issues unique to particular seams or between specific entities, as those issues may not be realized by other parties.”
“Therefore, blanket revisions may unnecessarily impact reliability and/or market aspects for other entities,” PJM’s Preston Walker said.
INT Standards
Also proposed for retirement are four interchange scheduling and coordination (INT) standards relating to interchange coordination, dynamic schedules, pseudo-ties and transmission loading relief procedures.
The SAR said the standards are duplicative of NAESB rules and that two of them are unenforceable because the “purchasing selling entity” is no longer a NERC registered function.
Duke also opposed the retirement of requirements 3.1, 4 and 5 of INT-006-4.
“We are not confident that this issue is adequately covered in the NAESB standards. Unlike the NERC standards which aim to promote reliability, the NAESB standards are commercially focused, and are not viewed as essential to maintaining a reliable system,” Thomas said. “We believe that not having these conditions outlined could negatively impact reliability.”
Morgan disagreed, saying requirements 4 and 5 are duplicative of the NAESB e-Tagging specifications “and are not a reliability-related task performed by a NERC registered entity.”
Washington state lawmakers approved legislation Monday requiring the state to rely entirely on zero-emissions and renewable energy by 2045.
Gov. Jay Inslee, a Democratic presidential candidate who heavily promoted the effort, said he looked forward to signing SB 5116 just after the state Senate voted to send it to his desk. Once that happens, Washington will become the fifth state — after Hawaii, California, New Mexico and most recently Nevada — to adopt a 100% clean energy mandate.
“On this Earth Day, I couldn’t be more proud of the Legislature’s action to pass the country’s most forward-looking clean energy bill,” Inslee said in a statement. “[T]his bill will fundamentally transform Washington’s energy future and transition us to 100% clean energy.”
Nevada Gov. Steve Sisolak signed legislation Monday to achieve a similar outcome. SB 358 requires Nevada to produce enough carbon-free electricity by 2050 to meet all of the state’s needs and to get half its electricity from non-emitting sources by 2030.
“Renewable energy is a major cornerstone of my economic development plan, and this bill will put Nevada back on the path toward renewable energy leadership on a nationwide level and continue to bring well-paying jobs to our communities,” Sisolak said in a signing statement.
Also on Monday, Public Service Company of New Mexico announced it was setting a goal of providing 100% emissions-free energy by 2040, five years ahead of the requirements set by the state’s clean-energy mandate. PNM said it was the first large investor-owned utility in the nation to establish such a goal.
“We … realized that we were not only up for the challenge of 100% emissions-free by 2045 but thought we can actually do it five years early while maintaining reliability and affordability for customers,” Pat Vincent-Collawn, PNM Resources chairman, said in a news release.
“The future is changing fast,” Vincent-Collawn said. “Here at PNM we are proud of how far we have come but know there is still so much to be done.”
The number of states, cities and corporations going all green has grown so quickly that some call it contagious.
The Sierra Club, which keeps an up-to–date list of state and local governments to join the movement, said this week 131 cities and counties, from Florida to Alaska, have committed to getting all their electricity from non-polluting and renewable resources and five cities — including Aspen, Colo., and Kodiak Island, Alaska — have met that goal.
The rapid spread raises concerns among utilities and regulators. During a meeting last week in Salt Lake City, Utah, many expressed concerns about having enough electricity to meet demand and maintain grid stability as fossil-fuel plants retire and intermittent renewables, such as wind and solar, proliferate. (See Westerners Wrestle with Resource Adequacy, Grid Reliability.)
Some who spoke at the joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB) said parts of the West could experience shortages soon.
Ann Rendahl, a Washington state regulator, said in the Pacific Northwest, “There’s increasing uncertainty there is sufficient resource adequacy in the next five years … Everyone is agreeing we’re approaching this point.”
David Mills, Puget Sound Energy’s senior vice president of policy and energy supply, said coal plants are closing, intermittent resources are saturating the market and natural gas plants, the “last backstop of reliability,” are retiring. He and other speakers urged Western states and utilities to create a centralized entity to oversee supply.
NextEra Energy officials said they expect the company to continue increasing adjusted earnings near the top end of a previously disclosed 6-8% growth rate for the year.
“I’ll be disappointed if we are not able to deliver [those] financial results,” CEO Jim Robo told analysts during an earnings call Tuesday.
The company reported first-quarter earnings of $680 million ($1.41/share), compared to $4.43 billion ($9.32/share) a year ago.
NextEra Energy’s Live Oak Solar Energy Center in Candler County, Ga. | NextEra
However, adjusting for federal tax reform and investments, NextEra reported adjusted earnings of $1.06 billion ($2.20/share), beating analysts’ expectations. The Florida-based company’s adjusted earnings a year ago were $929 million ($1.96/share).
Investors reacted by driving down the company’s stock slightly to $189.79/share, a 74-cent loss during the day. NextEra’s share price has gained 9.2% since the year began and 17% over the past year.
NextEra said the utility’s integration “continues to progress smoothly” despite the loss of about 7,000 customers in the aftermath of Hurricane Michael. CFO Rebecca Kujawa said the utility expects 60-80% of those customers to return, and it has filed to recover $350 million in restoration expenses.
The company said NextEra Energy Resources has added about 1 GW of renewable resources to its backlog, including its first co-located combined wind, solar and storage project. The wholesale supplier expects to develop more than 6.4 GW of wind and solar projects through 2020.
| NextEra
NextEra’s Florida Power & Light subsidiary announced in January a “30-by-30” plan to install more than 30 million solar panels by 2030.
Addressing NextEra’s reported $8 billion offer for South Carolina’s troubled state-owned utility, Santee Cooper, Robo said he expects a decision by June. The utility was involved in a failed effort to build the V.C. Summer nuclear plant.
“I think the state realizes Santee has upwards of $4-$5 billion of debt on an asset … that is never going to generate income,” Robo said. “I think the vast majority of folks in the state understand they need to address [this issue], and the key stakeholders are, I think, working hard to come to a conclusion about how the process is going to move forward. You can imagine we will continue to play in the process.”
PJM wants stakeholder feedback about whether its Distributed Energy Resource Ride Through Task Force should pivot in a new direction.
Susan McGill, manager of interconnection analysis, said Tuesday staff will poll members of both the Task Force and the Planning Committee in order to build a solutions package at its next meeting. The leading question, she said, asks stakeholders how comprehensive proposed rules for ride through settings should be, given the varied landscape of PJM’s 13-state grid.
“Originally, the thought was that PJM will develop a standard set of settings we would use across the PJM footprint,” she said. “But there’s a lot of facilities that don’t fall under FERC jurisdiction, and we wouldn’t have any authority to enforce those settings.”
PJM wants stakeholder feedback about whether its Distributed Energy Resource Ride Through Task Force should pivot in a new direction.
Before the widespread adoption of DERs, the grid was designed to handle one-way power flows, with energy moving from generating plants through the transmission system, before being stepped down to the distribution system and ultimately transmitted to end-use consumers. The growing volume of generation coming off the distribution network is forcing grid operators to rethink the system to accommodate unconventional flows.
PJM said DERs — including solar, battery storage, combined heat and power plants and some wind turbines — currently function on settings designed to respond to unexpected system malfunctions that disrupt power flow. Some sources “ride through” the event, providing much-needed reliability, while others “trip-off” to prevent system damage. Solar panels and other DERs also can’t tell the difference between a transmission fault and a distribution fault, causing inappropriate responses and overstressing the system.
The task force has been considering ways to fix this problem — even going so far as to bring in federal experts to help develop new standards — but McGill said stakeholder feedback so far has been limited. (See DOE Lab to Join PJM DER Integration Effort.)
She said the poll will help PJM decide when settings should be developed following one of the following directives:
Standard settings that should be used consistently for all DER facilities across the PJM footprint;
Standard settings that should be used for all FERC-jurisdictional DER facilities across the PJM footprint;
Recommendations that can be used when the local electric distribution company does not have a standard.
“Some transmission owners are already working standards to fit their unique distribution facilities,” McGill said.
Members will have a week from receipt to answer the poll. Staff will review the answers and use the results to construct a package of standards at the task force’s May 21 meeting.
The commission ordered SPP to refund, with interest, credit payment obligation amounts dating back to 2008, except for the one-year billing adjustment limit allowed in the Tariff. SPP has estimated the obligations to be approximately $200 million.
SPP was seeking a retroactive Tariff waiver allowing to invoice transmission service customers for Attachment Z2 credit payment obligations for the 2008-2016 time period prior. FERC ruled the waiver request to be retroactive ratemaking, saying SPP did not provide adequate notice.
“In my opinion, FERC had no idea of what it was unraveling,” Suskie told the MOPC on April 16. “We’ve listed 20 issues that are going to be challenges if we undo this.”
Included among those is how SPP will redistribute to transmission owners’ point-to-point revenues it had clawed back in the historical settlements process. Staff said it would share the full list of issues with stakeholders.
Suskie said SPP and other parties on April 1 asked FERC for a rehearing and clarification of the order (ER16-1341). He also said the RTO is developing a compliance plan to be filed with FERC no later than June 28.
Attachment Z2 details how sponsors that fund network upgrades can receive reimbursements through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. SPP said that delays in implementing computer software kept it from listing certain creditable upgrades in aggregate facilities study reports, calculating and assessing costs, and distributing credits to transmission customers before August 2016.
SPP Proposing to Assign Kansas NTC to GridLiance
SPP’s proposal to assign the Kansas Power Pool’s (KPP) notification to construct (NTC) a 69-kV rebuild to GridLiance High Plains met pushback from the MOPC over increased costs within transmission zones and the usual turf battles between the RTO’s legacy TOs and smaller entities.
“If this was someone else other than GridLiance, or another [investor-owned utility], you would gladly accept the assignment,” Tri-County Electric Cooperative’s Chris Giles complained to the committee’s membership.
“Amen!” came a voice from the opposite corner of the meeting room.
The project was originally assigned to KPP in February 2018. Rather than reconductor 4 miles of 69-kV lines from the city of Winfield, Kan. — a KPP member — to a Westar Energy substation, KPP decided on a full rebuild and raised the initial estimate from $1.5 million to $3.6 million.
Larry Holloway, KPP’s assistant general manager for operations, said his company has been unable to gain the obligation to build from Kansas regulators, which led to GridLiance’s involvement. The five-year-old company, which partners with public utilities, announced in January a “long-term partnership” with Winfield in which GridLiance would acquire 65% of the city’s 29 miles of 69-kV facilities and invest in a “needed reliability upgrade.”
SPP said GridLiance’s own data show it will increase the annual cost to customers if it retains the NTC, largely because its tax requirements are greater than KPP or Winfield’s.
GridLiance High Plains President Brett Hooton said the cost of the project itself remains the same, regardless of the assignment from Winfield to GridLiance. He said SPP’s cost estimate over the project’s four-year life works out to $75,000/year.
“The cost difference on rates primarily relates to the fact that GridLiance is a taxable entity and the city is not,” Hooton told RTO Insider. “Any time there is an assignment from a municipal utility to a taxable utility, there will be similar cost impacts.”
Hooton said GridLiance intends to build the facilities with 138-kV capabilities, matching Westar’s existing infrastructure.
The issue is likely to receive similar pushback during the April 29-30 Regional State Committee and Board of Directors meetings. SPP’s Tariff required staff to “advise” the MOPC of the proposal, with the final decision being left to the board.
“If the board were to reject the assignment because of the small cost impact, it would set a precedent that municipal utilities would virtually be unable to ever assign or novate an NTC because of their tax-exempt status,” Hooton said.
Staff Explains 9-Month Delay to New Settlement System
Staff briefed the MOPC on its delayed new settlement system, which was supposed to go live May 1. However, a condensed project timeline and missed deliveries left developers without enough time to build software and train end-users, pushing the implementation back to Feb. 1, 2020.
SPP announced the delay to project participants on Feb. 15, saying the project was in red status because of “various system issues” and that it was pausing member testing as it reassessed the timeline, remaining work and required testing.
Settlements Director Don Shipley said incorporating additional applications and links to other systems increased the project’s risk. The settlement system replacement project will consolidate several systems and automate manual processes, reducing staff costs and improving personalized customer service, he said.
“We had several parallel paths — development, testing, training — all going on at the same time, rather than back-to-back,” Shipley said.
Shipley said the inability to run the system end-to-end meant staff couldn’t do day-in-the-life testing, which also meant members couldn’t “appropriately” test their internal systems. Even then, there were frequent errors in the software’s calculations, he said.
“The right decision was to delay and ensure we have a system that worked. The most catastrophic thing that could happen is if we couldn’t settle the entire system when we cut over,” Shipley said.
Following several weeks of analysis and review, SPP has worked to improve its communications both internally and with the vendor, Symphono. Daily meetings, called “scrums,” are held to “understand what is going to be happening” and to discuss any issues at the vendor level. Staff are now focused on the “total development effort,” with a June 28 deadline to complete all code, and internal testing and training has been increased.
“We don’t want this to become a pattern. What are we doing to learn from mistakes like this and Z2 to ensure it doesn’t happen again?” asked Kansas City Power & Light’s Denise Buffington, the MOPC’s vice chair.
“I understand where you’re coming from, with the Z2 followed by the settlement system,” Shipley said. “We’ve already applied some of the lessons learned from Z2, so it’s an incremental process. We still have to understand how we efficiently deliver projects.”
“Communication is critical. Everyone has to be talking to each other,” said SPP’s engineering vice president, Lanny Nickell. “We tend to overcomplicate things, and we tend to be optimistic. We tend to set very aggressive schedules.”
Shipley was reluctant to lay the blame on Symphono, which built a similarly customized system for MISO. He said because of SPP’s larger footprint and “the way we settle,” SPP needed “something different.”
“I do think we underestimated some of the complexities of adding [other capabilities] to our systems,” he said. “This vendor worked very hard with us. They made mistakes and missteps, but we did as well. We all bear some responsibility of where we were in February. We all bear the responsibility of the new timeline.”
The project was approved two-and-a-half years ago with an estimated capital cost of $5.3 million. The implementation delay has not increased those costs, SPP said, but will likely result in additional maintenance costs because the existing settlement system and other legacy systems and software will run longer than planned.
FERC on Thursday granted SPP’s request to defer several Tariff changes because of the settlement system’s delay (ER17-1568). The Tariff revisions were filed because of changes to other systems as a result of the new settlement system. (See related story, “SPP Granted Delay for Tariff Revisions,” FERC Tells SPP to End Exit Fee for Some Members.)
SPP Broadens PMUs’ Reach with Revision Request
SPP will get another chance to widen the use of phasor measurement units (PMUs) within its footprint with the MOPC’s approval of a revision request (RR) that addresses a FERC rejection of a previous RR.
RTWG RR340 changes the PMUs’ installation location from the point of interconnection to the point of change of ownership and classifies equipment as “transmission owner interconnection facilities” to fully address cost responsibility. The RR also adds language to allow existing equipment to serve as a PMU.
“This just clarifies the cost issue and where [PMUs] will be installed,” said American Electric Power’s Richard Ross during the heat of discussion.
The recommendation was passed over two opposing votes and a half-dozen abstentions, primarily over installation costs.
RR340 is a response to a previous change request that would have required PMUs at new generator interconnections but was rejected by FERC in August. The RTWG said the commission found the language regarding the PMUs’ installation funding unclear. The commission directed SPP to clarify how TOs will treat PMU installation costs to avoid including them in transmission rates. (See “Commission Rejects PMU Proposal over Cost Concerns,” 3rd Time’s a Charm for SPP Resource Adequacy Proposal.)
“This RR is trying to get in front so that we can capture more PMU data as it is brought on,” said Cody Parker, SPP’s supervisor of operations support.
Parker said the RTO has completed the first phase of its PMU project, creating an informational-only system not used in real-time operations. Subsequent phases will be dependent on increased PMU coverage, he said.
SPP defines PMUs as monitors that provide precise grid measurements for synchrophasors. PMU measurements are taken at high speed, typically at 30 observations/second. Each measurement is time-stamped according to a common time reference, allowing measurements from different locations and utilities to be synchronized and combined to provide a precise and comprehensive view of the entire interconnection.
DER White Paper Gains Endorsement
The MOPC endorsed a Supply Adequacy Working Group policy paper that further defines the requirements for demand response programs and behind-the-meter generation and addresses whether to treat them as a load modifier or capacity.
The Distributed Energy Resources Policy is intended to ensure that all net peak demand is carrying the appropriate capacity, as required by SPP’s resource adequacy requirements. SPP’s Tariff allows a load-responsible entity to reduce its forecasted peak demand through DR programs and controllable and dispatchable BTM generation.
MOPC members debated the need to require DERs to attest to having firm transmission service to load, as the paper’s draft required. Oklahoma Gas & Electric’s Greg McAuley suggested the phrase “attest to having firm delivery to load” be used instead of “transmission service,” which helped to gain approval against one dissenting and one abstaining vote.
“Some of the potential resources in [the controllable and dispatchable resource] category are behind retail meters and, as such, may never impact the transmission system and, therefore, would never need or have firm transmission service,” McAuley explained.
The nine-page white paper, which has been approved by the SAWG and the Cost Allocation Working Group, will be turned into a business practice and eventually become an attachment to the Tariff’s Attachment AA.
HITT Working to Finalize Report to Board
Suskie told the committee that the Holistic Integrated Tariff Team hopes to complete its yearlong work by the end of the month and present a final report to the Board of Directors for its April 30 meeting.
Composed of stakeholders, regulators and staff, the HITT has entered the third phase of its work in drafting and finalizing a report to the board. The team has been meeting since April 2018 to determine the optimal alignment of SPP’s planning processes, cost-allocation methodologies, and market products and services. (See SPP’s Tariff Team Begins Carving up the Elephant.)
“We remain positive we can get through the end of the month, but we have left the most contentious issue for last,” said KCP&L’s Buffington, referring to zonal transmission cost allocations.
“Like when the U.S. Constitution was drafted, there are a lot of different people on different sides,” Golden Spread Electric’s Mike Wise said. “I’m very optimistic that as a group, we are going to achieve what we set out to do, which is achieve value for members of the pool. Not everybody is going to be happy with it. I have compromised; Denise has compromised. I’m encouraged, very encouraged, where we are right now.”
The HITT meets in Dallas on April 25 to complete the report. It has posted a draft version on its website.
The MOPC unanimously approved a recommendation by the Market Working Group and RTO staff to improve the RR process’s impact analysis by revising the cost data that go into calculations.
SPP’s Gary Cate said the new methodology will provide a clear view of estimated vendor costs by no longer including capitalized costs, including those staff salaries that are already accounted for in the capital budget. The changes will also add transparency into staff time by adding the “true impact” to staff within the implementation timeline.
Staff costs will only include staff hours and remove redundant cost reporting between the capital and foundation budgets. Cate said the current method inflates staff cost by lumping average salaries into the cost of impact assessments.
With the change, impact analyses will provide a range of vendor costs rather than a single value with a rough order of magnitude +/- 50%.
Members greeted Golden Spread’s Natasha Henderson with applause when she joined the meeting, fresh off completing her second Boston Marathon the day before. Henderson battled unexpectedly warmer temperatures that slowed her pace, but she used a finishing kick to reach the finish line in just under four hours.
“I thought about dropping, but who drops out of the Boston Marathon? Not me,” Henderson told RTO Insider. A personal best and qualifying for next year’s marathon out of the question, she said, “this was now going to be a very long training run.”
Golden Spread’s Natasha Henderson crosses the finish line. | Natasha Henderson
Henderson was scheduled to run a half-marathon in early June in Steamboat Springs, Colo., but has changed her registration to run the full 26 miles in an attempt to qualify for next year’s Boston Marathon.
“Some days, like my second Boston Marathon, are not what I hoped they would be, but they make me stronger,” Henderson said. “For me, running is about pushing myself and being a better person. I learned from the experience and hope to have another Boston Marathon in my future.”
Members Pass 10 RRs on Consent Agenda
The MOPC unanimously endorsed its consent agenda, which consisted of 10 revision requests:
BPWG RR343: Automates a manual task with installed software to prevent interchange overscheduling.
BPWG RR344: Retires Business Practice 2500, which was implemented when the aggregate transmission service study could take years to complete. The study’s methodology has been revised to include a six-month completion requirement, making the practice obsolete.
MWG RR346: Includes transition major maintenance among the costs associated with start-up and no-load operations to be included in mitigated no-load and start-up offers beginning with the April 18, 2019, operating day.
ORWG RR338: Expands and clarifies the description of “most severe single contingencies” and other potential contingency events used to determine the reserve sharing group’s contingency reserve obligation.
ORWG RR349: Requires responsible entities to use the reliability communications tool (R-comm) instead of telephones to communicate with the SPP balancing authority.
RTWG RR345: Limits to three the number of identical transmission service requests impacting a DC tie during the submission window, as outlined in NAESB Business Standard WEQ 001-8.3.
RTWG RR347: Removes grandfathered agreements that have expired or are no longer in service.
RTWG RR353: Revises language in Tariff Attachment V to account for changes in RR335, which adds a three-stage generation interconnection study process and implements required changes in FERC Order 845-A.
STAFF RR351: Clarifies and modifies the RR process requirements, allowing change requests to be withdrawn without requiring MOPC review and action. Any actions may still be appealed by qualified entities to the MOPC.
TWG RR350: Eliminates language in the criteria that is already covered by NERC standards or other SPP standalone documents, minimizing inconsistencies or conflict with current and future NERC standards and revisions.
The Texas Public Utility Commission last week held off on giving its final blessing to $1.37 billion worth of transactions involving Oncor, Sharyland Utilities and Sempra Energy.
Handed a proposed order by Oncor the day before their Thursday meeting, the commissioners asked staff to bring a final order back to its May 9 meeting (Docket 48929).
PUC Chair DeAnn Walker opens the April 18 meeting.
“I’m OK with going ahead and approving the settlement,” said PUC Chair DeAnn Walker, drawing assent from her fellow commissioners.
The commission’s final order will give Sempra a 50% stake in Sharyland Distribution & Transmission Services and Oncor ownership of Sharyland’s transmission-owning InfraREIT. The asset exchange will increase Oncor’s footprint in West Texas and “de-REIT” the Sharyland utility in South Texas. (See Oncor-Sharyland-Sempra Deals Inch Toward Approval.)
“We look forward to continuing the dialogue about the draft order,” Oncor spokesman Geoff Bailey said. “We continue to believe that Oncor’s proposed acquisition of InfraREIT is good for Texas, the ERCOT market and for Oncor.”
Oncor to Pay $432K Penalty
The PUC’s consent agenda included the approval of a settlement agreement between staff and Oncor that will result in the utility paying $432,000 in administrative penalties for 2017 feeder violations (Docket 48841).
PUC commissioners confer with Stephen Journeay, director of commission advising and docket management.
Following an executive session, the commissioners also agreed to intervene in three FERC dockets:
ER19-1503: MISO and Entergy Services’ proposed revisions to Entergy operating companies’ transmission formula rate templates.
EL19-62: Springfield’s (Mo.) complaint against SPP over its pricing zone costs as a result of the RTO’s highway/byway allocation methodology. Springfield is asking FERC to “benefit-deficient zones,” like Springfield’s, from the methodology’s “unintended consequences.”
ER19-1541: A proposed settlement agreement between MISO, its transmission owners and East Texas Electric Cooperative over the withdrawal and transfer of 38 MW of load and related assets from MISO to SPP.
WASHINGTON — Record high natural gas demand and production highlighted FERC’s 2018 State of the Markets report, released last week.
The report by the Division of Energy Market Oversight said gas demand was driven by electric generation and growing LNG exports. Despite big jumps in the Marcellus Shale and the Permian Basin regions, demand growth outpaced production increases.
As a result, storage levels were lower than average and “at times were the lowest in more than a decade,” FERC said, contributing to higher gas and power prices.
The Henry Hub benchmark averaged $3.12/MMBtu for the year, up 5% from 2017. Reduced storage inventories pushed Henry Hub prices up 31% in the fourth quarter over a year earlier.
| FERC
Although gas prices remained relatively low, there was increased price volatility because of storage constraints, extended winter cold and infrastructure constraints in the West. In January 2018, an East Coast cold snap pushed gas prices to $140.85/MMBtu in New York and $128.39/MMBtu in the Mid-Atlantic, with prices peaking at $78.88/MMBtu in Boston. In contrast, New York’s spot price never reached $21/MMBtu in 2017.
Gas production averaged 80.7 Bcfd, an increase of 12% from 2017. The Marcellus Shale was the most productive basin, averaging 19.4 Bcfd for 2018, up nearly 13.5% from 2017.
Haynesville Shale production jumped to an average of 6.5 Bcfd, a 46% increase that FERC attributed to higher gas prices and lower production costs. Rising crude oil prices were a factor in the 2.1-Bcfd increase in associated natural gas production in the Permian, a jump of 41%.
More than 689 miles of commission-jurisdictional pipelines, representing 13 Bcfd of capacity, went into service during 2018, much of it connecting Marcellus and Utica supplies to markets in the Midwest, Northeast and Southeast. There was no capacity increase in New England.
| FERC
Export Growth
New pipelines also provided links to LNG export terminals and exports to Mexico.
After becoming a net gas exporter for the first time in 60 years in 2017, U.S. net exports were almost 2 Bcfd in 2018, in part because of the opening of the Cove Point LNG facility in Maryland in March and the expansion of the Sabine Pass LNG terminal in Louisiana in October. LNG exports averaged nearly 3 Bcfd in 2018, a 50% jump from 2017.
Pipeline exports to Mexico rose almost 0.5 Bcfd to a new high of 4.6 Bcfd.
| FERC
The report predicted up to 4 Bcfd of new export capacity will be added in 2019, with LNG facilities at Cameron, Corpus Christi, Elba Island and Freeport expected to go into service and an additional expansion at Sabine Pass. (See related story, Enviro Protesters Scale FERC HQ as Agency OKs More LNG.)
Power Prices Rise
As gas continued its increasing role in electric generation, fuel price increases also caused a jump in power prices across the country.
Mean day-ahead on-peak LMPs jumped almost 25% at RTO/ISO pricing nodes. Prices in SPP, MISO and CAISO increased less than 15%, while PJM and NYISO prices rose about 20%. ISO-NE was up 33% and ERCOT had the biggest jump at 44%.
As in recent years, most new generation capacity in 2018 was natural gas, wind and solar, and most retirements were from coal.
| FERC
Capacity price trends varied in grid operators’ 2018 auctions. RTO-wide average prices declined 13% in New England’s auction for 2021/22, while the weighted average price in PJM’s auction for the same period rose 36%.
In NYISO’s spot capacity auction, prices in the high-cost Hudson Valley and New York City zones fell by 3% or more. Prices for Long Island rose 5% and the New York Control Area jumped 32%.
MISO’s Planning Resource Auction saw zonal prices rise clear much lower than in the other markets with a price of 30 cents/kW-month for most of the region for 2018/19, up 25 cents from a year earlier.
PJM wants FERC to toss out the Independent Market Monitor’s complaint about its default market seller offer cap (MSOC), saying the IMM’s February filing did not prove current rules encourage abuse of market power (ER19-47).
In an April 9 response filed with the commission, PJM said the Monitor didn’t provide enough evidence that its current cap — approved four years prior as part of the RTO’s Capacity Performance construct — and the results of Base Residual Auctions suddenly became unjust and unreasonable.
PJM said the commission’s order approving CP “explained that the default MSOC is just and reasonable because it reflects the amount that a competitive resource would accept to be committed as a capacity resource.”
“In particular, it is designed to allow capacity market sellers to recover the costs, investments and expenses needed to ensure that their resources can perform during emergencies occurring at any time of the year. In other words, the default MSOC is intended to reflect the opportunity cost that a resource faces when choosing whether to become a committed capacity resource,” PJM said.
PJM said the Market Monitor isn’t authorized to file a complaint on the market seller offer cap. | PJM
The Monitor said in its initial filing that PJM’s MSOC has been inflated by the “unreasonable and unsupported” expectation of 30 performance assessment hours (PAHs) annually. As a result, the Monitor said, it has been prevented from effective mitigation of market power, able to subject only a small number of very high offers to unit-specific cost reviews. (See Monitor Asks FERC to Cut PJM Capacity Offer Cap.)
Unit-specific MSOCs are supposed to be based on the opportunity cost of taking on a CP obligation, with its expectations of bonus payments or penalties for performance during an emergency, PJM said. (The time span for measuring performance was changed from PAHs to five-minute performance assessment intervals (PAIs) in compliance with FERC Order 825 in 2018.)
In August, the Monitor concluded that ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 BRA because of economic withholding encouraged by the inflated MSOC. (See IMM: PJM 2018 Capacity Auction was ‘Not Competitive’.)
PJM asked the commission to reject the Monitor’s proposed replacement rate of 60 PAIs and instead adopt a method that applies the same measurement to equations for both the default MSOC and the nonperformance charge. This rate, the RTO asked, would not take effect until after the 2022/23 BRA, for which several compliance deadlines for market sellers have already passed.
“The Market Monitor’s proposal is unjust and unreasonable due to, among other reasons, the disconnect between the number of expected performance assessment intervals in the nonperformance charge rate and the default MSOC,” PJM said. “Retaining the same value of performance assessment intervals in both equations is essential to maintaining the underlying logic of the existing default MSOC equation.”
After prodding by stakeholders, MISO now says it will boost renewable generation estimates in each of the four 15-year future scenarios that guide its annual transmission planning process.
MISO had previously proposed relying on an older set of futures to inform the 2020 Transmission Expansion Plan (MTEP 20). But stakeholder pushback prompted the RTO to increase the minimum renewable penetration levels for each future by 5%, bumping projections from 15-35% of the generation mix to 20-40%.
Speaking at a Planning Advisory Committee meeting Wednesday, MISO Planning Manager Tony Hunziker noted the high degree of consensus among stakeholders to increase renewable estimates.
Increased renewable projections in MTEP 2020 futures | MISO
The MTEP will also assume the solar investment tax credit — which allows a 30% federal tax deduction of installation costs — will continue into 2023. The RTO will also rely on the National Renewable Energy Laboratory’s Annual Technology Baseline capital cost projections for renewable generation instead of using a 30% variance on those projections.
However, some stakeholders said they’d like to see a more nuanced approach to projecting renewable growth based on subregional characteristics to avoid blindly increasing renewable projections. For instance, MISO shouldn’t expect significant wind generation growth in sunny MISO South, some noted.
“MISO is not a resource planner. We don’t dictate renewable resource additions,” Hunziker responded.
Entergy’s Yarrow Etheredge said MISO didn’t adequately support the case for a blanket increase of every type of renewable generation everywhere in its footprint.
“This is basically just an adder,” Etheredge said, asking MISO to defend the change using data.
Hunziker promised a complete rework of MTEP 21 futures with stakeholders and reminded PAC members that MISO was up against a June deadline to finalize MTEP 20 futures definitions and assumptions.
The RTO last month said it would rely on the same set of 15-year futures for the third straight year to evaluate transmission projects in MTEP 20, though some stakeholders criticized the RTO’s limited fleet change future as no longer a likely scenario. (See MISO Going Back to the Futures for MTEP 20.) The futures scenarios include a limited fleet change, continued fleet change, accelerated fleet change, and a distributed and emerging technologies future.
Hunziker said the renewable increase should alleviate specific concerns about MISO’s limited fleet change future, which has been criticized as improbable because it projects only an 11-GW growth in renewable generation through 2033. MISO’s interconnection queue currently includes about 420 projects worth a combined 70 GW; renewable resources account for about 90% of the queue. Historically, about 18% of proposed projects clear the queue.
Last month, members of MISO’s Board of Directors also questioned whether the limited fleet change future was still plausible.
“It seems like the rate of adoption is increasing,” Director Thomas Rainwater said, while also acknowledging that MISO is “no California” in terms of appetite for renewables. He asked if the RTO will consider “a more radical adoption” of renewables and distributed resources in a new set of futures for MTEP 21.
MISO Vice President of System Planning Jennifer Curran said the accelerated fleet change and distributed and emerging technologies scenario are fast becoming the most probable futures and noted the RTO will soon revisit how futures are developed. But she also cautioned that MTEP futures represent possible trends and are not meant to be forecasts.
At the April PAC meeting, Minnesota Public Utilities Commission staff member Hwikwom Ham said he remained concerned that the limited fleet change and continued fleet change scenarios still risk obsolescence because they don’t account for the zero-carbon pledges of multiple utilities and increasing electrification of the economy. He also pointed out that equity investors are now contemplating a company’s carbon footprint as a risk factor before making investments decisions.
“Who is going to be in the White House next year? It’s going to be a different business model,” Ham added, referencing President Trump’s rollbacks of environmental regulations.
Hunziker said MISO will raise those topics in the redevelopment of futures in time for MTEP 21.
Meanwhile, MTEP 20 marks the first time MISO will work with Purdue University’s State Utility Forecasting Group and Applied Energy Group to create separate load forecasts that reflect each of the four futures. The RTO this month reported that entities representing 77% of its load responded to its request for load, demand and energy data.
