At last week’s National Association of Regulatory Utility Commissioners Summer Policy Summit in San Diego, attendees were encouraged to download an app to facilitate in-person meetings. There’s just one problem: Were it subject to the privacy rules adopted by commissions in several states, the app would be in violation.
Murray
Privacy rules prevent electric and gas utilities from selling or disclosing personal information except under certain, carefully monitored circumstances. Customer protections, such as clear notices to users about what data are being collected, are absent from the app. This leads to an embarrassing double standard for some state regulators. While commissioners enjoy the conveniences provided by the “NARUC 2017” app, their own rules would outlaw similar practices in their home states.
For example, take California’s rules. In 2011, the Public Utilities Commission issued a lengthy privacy decision that requires software companies that access customer data held by a regulated utility to provide written privacy policies that are “meaningful, clear, accurate, specific and comprehensive.” But, confusingly, the app links to two privacy policies that are sometimes in conflict with one another. The policies also do not explain what personal information is captured by the user’s mobile device — a clear violation of California’s rules.
Another California requirement is for software companies to distinguish “primary purposes” from “secondary purposes” of the personal data used. A primary purpose could be “to help you save energy and money in your home with tailored recommendations on your smartphone,” while a secondary purpose could be, for example, selling the data to make extra money. Secondary uses are explicitly prohibited without the prior written consent of the customer. Unfortunately, NARUC 2017’s terms say vaguely, “We will collect and use of [sic] personal information solely with the objective of fulfilling those purposes specified by us and for other compatible purposes.” Thankfully, the app’s developer has an agreement with NARUC not to sell any users’ personal data, according to the company’s CEO. But if a complaint were filed in California against a similar app maker, the commission would likely find the software unlawful.
Other commission-approved rules require companies to make informational disclosures to consumers prior to releasing personal data. By standardizing disclosures, the idea is that companies are prevented from writing their own vague or misleading language that exploits customers. For instance, Pacific Gas and Electric’s form for demand response is four pages long, and deviations from the form are not allowed.
Outside of California, Colorado and Illinois regulators have approved standardized disclosure language. But the NARUC 2017 app does not ask for any specific authorization at all, and, when it does, the authorization language is fluid. Both of its policies say that the app maker “may revise these terms of use at any time without notice.” Changing terms without notifying users is anathema to privacy advocates and consumer groups who fought for rules that ban the practice.
Finally, California’s rules enshrined the principle of “data minimization,” the idea that only the personal data necessary for the task should be collected. Presumably, an app to help people at conferences meet face to face would need information like your name, title, organization, location and which sessions you want to attend. However, the NARUC 2017 app requires users to give it permission to much more, such as the right to read and modify any file stored on your device; to create new Bluetooth connections; and to control the phone’s networking settings — none of which are clearly tied to helping people meet at a conference.
It is ironic that many state commissions publicly take a “tough on privacy” stance that is at odds with their national association’s practices at its summer conference. But the double standard is not altogether surprising. Since the advent of smartphones, consumers have routinely traded their personal data for access to free services. Commission requirements for paper forms appear increasingly out of step with modern technology.
Over time, as sharing personal data such as banking transactions and health data with tech companies becomes easier, it is worth re-examining the utility industry’s practices. Is it reasonable to give away the data on your phone with a single click, while your utility bills require filling out a four-page legal form?
To be clear, the NARUC 2017 app would only violate commission rules if it accessed users’ energy information or customer account information held by utilities. Apps that do not request data from a utility operate without commission oversight.
Nevertheless, as leaders in the public sector, state commissioners and their national association should lead by example. Entrepreneurs in software and energy management have a saying: “Eat your own dog food.” It means that entrepreneurs should use their companies’ products in their personal lives, to live by their creed. We encourage NARUC to do so as well.
Michael Murray is president of Mission:data Coalition, a national coalition of more than 40 innovative technology companies that empower consumers with access to their own energy usage data. We strongly believe that energy management technologies can flourish while simultaneously protecting customer privacy. For more information about privacy and state private rules about energy, see our whitepaper, “Got Data?”
NYISO reported Monday that locational-based marginal prices (LBMPs) for June averaged $31.76/MWh, nearly unchanged from May but up 16% from June 2016. Year-to-date monthly LBMPs averaged $36.01/MWh through June, a 20% increase from a year earlier.
In a July 24 Market Operations Report to the ISO’s Business Issues Committee, Rana Mukerji, senior vice president for market structures, said natural gas and distillate prices fell from the previous month but gained 27.5% year-over-year. Natural gas prices at Transco Z6 NY averaged $2.35/MMBtu in June, down from $2.80 the previous month.
Gulf Coast jet kerosene for the month came in at $9.59/MMBtu, down from $10.47 in May, while ultra-low sulfur No. 2 diesel at NY Harbor was $10.14/MMBtu, compared with $10.82. Distillate prices dropped 5.4% from a year ago.
On Capacity Exchange, Probabilistic Method not Better
A new probabilistic method to limit capacity price increases caused by exports from an import-constrained area would complicate the process and offer results no better than the current deterministic method, according to an analysis conducted for NYISO by GE Energy Consulting.
Mukerji shared the analysis from the monthly Broader Regional Markets Report as the latest development arising from FERC’s January acceptance of the ISO’s capacity revisions while rejecting a proposed one-year transition as lacking an “analytical basis” (ER17-446). A NYISO analyst briefed stakeholders on the outlines of the study at the April Business Issues Committee meeting. (See NYISO Provides Update on Capacity Export Concerns.)
Probabilistic Locality Exchange Factor Analysis | GE Energy, NYISO
NYISO proposed the plan last fall to address anticipated price spikes in the capacity market in the Lower Hudson Valley and New York City zones expected after the commission in October allowed a New York plant in a constrained zone to export into ISO-NE. (See FERC Sides with ISO-NE in Capacity Dispute with NYISO.)
The new rules use a locality exchange factor to reflect how much capacity from “rest of state” can replace capacity exported from an import-constrained locality. The prior rules assumed that 100% of a generator’s exports from an import-constrained area must be replaced with generation in that locality.
“The probabilistic method introduces uncertainty and does not give results which differ significantly from the 47.8% found using the current deterministic method,” the analysis said. That figure represents an estimate of the percentage of exports from NYISO zones G-J to ISO-NE that could be expected to be replaced by “rest of state” capacity. NYISO compromised with an 80% figure.
Stakeholder comments on the methodology analysis were due by July 14. FERC in its January order encouraged a robust stakeholder-driven process but said “we cannot accept NYISO’s proposal for a one-year transition based solely on stakeholder support.”
SAN DIEGO — More than 1,000 people attended the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week. Here’s some of what we heard.
Sunrun CEO Lynn Jurich said that the task for regulators and industry is to figure out what value distributed energy resources bring to the grid, and which business models and rate designs would work best. She said rooftop solar could be connected directly at the utility level to be dispatched when it is needed.
“Too often we are stuck fighting rate designs that appear to slow the growth of the rooftop solar,” Jurich said. “Let’s work together to actually maximize the value of these assets to the entire system.” Solar companies know how to market the technology to consumers, but utilities best know how to integrate the systems in the most efficient way, she said.
NuScale Power Vice President Jack Bailey said that the Nuclear Regulatory Commission is reviewing the company’s small modular reactor design, but it will take 46 months to approve the 12,000-page application. Oregon-based NuScale is the first small modular reactor company to seek approval of the technology. The company filed for approval of its design in January, an effort that took more than 800 people over two years. The 12 50-MW modules — 600 MW in total — are planned to be built on the site of the Idaho National Laboratory, owned by Utah Associated Municipal Power Systems and operated by Energy Northwest.
Asked what the reaction has been from the environmental community, Bailey said, “I would say it’s a mixed bag overall, but we are seeing some support.” He is also hopeful that the federal government will take steps to solve the problem of where to store spent nuclear fuel.
Katrina McMurrian of Nuclear Waste Strategy Coalition said she is hopeful the federal government will revisit the stalled Yucca Mountain nuclear waste disposal site in Nevada. The U.S. Nuclear Waste Fund contains more than $40 billion, accruing interest of $1.5 billion/year, but fee collection has stopped because of a suit brought by NARUC and others.
President Trump proposed to restart Yucca with $100 million in his budget proposal, and $10 million for an interim storage program to a private or federal facility while Yucca is completed.
The Senate last week approved funding for an interim storage site for nuclear waste, but unlike the House of Representatives, did not include money for restarting Yucca. “The hope is to see both sides put something together that they can conference and actually fund both of these priorities,” McMurrian said. Rep. John Shimkus (R-Ill.) has introduced legislation that would set a time limit for NRC to approve Yucca and allows the Energy Department to permit an interim facility while the facility is licensed.
Dipka Bhambhani, communications director of the United States Energy Association, said her group is working with the International Gas Union to support the 27th World Gas Conference in D.C. on June 25-29, 2018. It will be the first time in 30 years that the U.S. has hosted the triennial event, which has been held since 1931, and the first time that the host country is both the largest producer and consumer of natural gas, she told the NARUC Gas Committee. USEA is a liaison to the Energy Department for the conference and is helping to manage communications for the event.
Environmentalists last week urged FERC to decide whether states can control participation of energy efficiency resources (EERs) in RTOs, while state officials said the commission should take no action.
The group Advanced Energy Economy petitioned FERC on June 2 to issue a declaratory order ruling that it has “exclusive jurisdiction” under the Federal Power Act to regulate EER aggregators involved in wholesale markets (EL17-75). AEE further requested that FERC make clear that retail regulators, such as state public utility commissions, have no such authority unless FERC grants it to them.
The group — whose members include Johnson Controls, Landis+Gyr, Lockheed Martin and other technology companies — asked FERC to rule after PJM began a stakeholder process to examine how it allows EER aggregations to participate in its wholesale markets. The initiative also was to investigate the potential for creating an “opt out” mechanism for regulators like what PJM developed for demand response in response to Order 719.
PJM’s initiative began after the East Kentucky Power Cooperative discovered an aggregator was attempting to sell into the RTO’s markets EERs that originated in its distribution territory. EKPC requested a legal opinion from the state Public Service Commission, which responded and later provided a declaratory order denying aggregators the right to sell Kentucky EERs into PJM’s markets without receiving its blessing.
At the Kentucky commission’s request, PJM then proposed the stakeholder process, which received substantial discussion before being endorsed. Rick Drom, an attorney representing the still-unidentified aggregator in Kentucky, argued that the process was “a flawed solution seeking a problem,” while PJM’s Denise Foster defended the RTO’s actions as reasonable preparation to develop appropriate rules should a regulatory agency act. (See “EE Problem Statement Narrowly Approved,” PJM Market Implementation Committee Briefs.)
Stakeholders from around the country weighed in last week before the deadline on filing comments. PJM said it neither supports nor opposes the petition, but it asked FERC to clarify states’ role “relative to retail customers that participate, either directly or indirectly, as supply-side EERs in the PJM capacity market.”
The Sierra Club, the Natural Resources Defense Council, the Sustainable FERC Project and the Environmental Defense Fund filed in support of the request. They supported AEE’s argument that there is no “nexus” between aggregating the EER credits and impacts on retail electricity usage.
“Because the transaction creating the EER occurs at the level of the manufacturer or the distributor of the energy efficiency product, a retail regulator’s authority over retail customers is not implicated,” according to a joint filing from the environmental groups. “We urge FERC to issue a focused order that resolves the cloud of uncertainty hanging over the participation of wholesale EERs in PJM’s market, while carefully avoiding a broad determination of state-federal jurisdiction that would be unnecessary and detrimental to the flexibility inherent in the statute.”
It also asked FERC to “redirect” PJM’s stakeholder process, saying the RTO “wrongly predetermined the framing and outcome of the process to address concerns about retail interactions of EERs.”
The Organization of MISO States, the Kentucky PSC, Kentucky Attorney General Andy Beshear, the Illinois Municipal Electric Agency (IMEA), the American Public Power Association and the National Rural Electric Cooperative Association all filed in opposition to the petition.
The Kentucky parties, filing jointly, argued that the sales do “have a direct nexus with retail electric customers” and that EE aggregation pose a “significant, adverse impact” to load-serving entities in the state. Energy savings are not separate from sales because PJM defines EERs as a “continuous reduction” in consumption, they said.
“The Kentucky parties argue that such sales would solely benefit the EER provider to the detriment of the LSE’s retail ratepayers,” they said. “Absent a retail customer’s load reduction, there is no EER to participate in the PJM market. The fact that the EER bidder has no contract or agreement with the retail electric customer, who may not even know that it is participating in the PJM wholesale market, is irrelevant. If the retail electric customer’s load reduction is bid by an EER into the PJM market, that customer is indirectly participating in the wholesale market.”
Unknown aggregations would cost ratepayers money, they argued.
“Absent inclusion of the EERs in the resource assessment of a Kentucky utility, it will either over procure capacity, resulting in higher than necessary costs for retail customers, or have excess capacity that should have been sold to benefit retail customers. Thus, without participation through a tariff or special contract, EERs in Kentucky are being enriched by higher rates paid by the utility’s other retail customers,” they said.
IMEA asked FERC to reject the petition and let the PJM stakeholder process play out. It argued that allowing aggregators to pull out individual customers from LSEs can threaten their financial and resource planning while “allowing a customer that provides no benefits to the system or to Milltown’s [a fictional IMEA municipal member] other customers to access the revenue [streams] from PJM’s markets to the detriment of [the LSE’s] own system benefits and ratepayers.”
NRECA also said the petition was premature, as PJM hasn’t developed tariff language and Kentucky hasn’t taken any action to limit EER bids.
“Too many facts are unknown, and the scope of the declaratory relief being sought is ill-defined,” NRECA spokesperson Tracy Warren said. “And in no case should FERC revisit the basis for its 2008 order on DR bids, as the petition invites.”
OMS filed in support of using the same “opt out” process as developed for DR in Order 719. “Wholesale EERs present the same type of concerns that were raised during the robust process leading to the issuance of Order 719.”
The organization warned that allowing EE aggregator participation would impact utility planning and attainment of mandated efficiency targets.
“It’s worth noting that the single energy efficiency program type that AEE relies on throughout its petition, reducing product cost directly at a retailer/supplier, typically has a very high [benefit-to-cost] ratio and is often a centerpiece of utility energy efficiency programs. By allowing aggregators to sign up retailers and suppliers for purpose of generating wholesale EERs, those same retailers and suppliers are no longer available to utilities to implement their own programs. Furthermore, the utility may have assumed the availability of certain retailers to participate in a utility efficiency program,” OMS said.
DENVER — SPP announced Tuesday it will dissolve its Regional Entity (RE), ending the reliability oversight role that had been a source of concern at NERC and FERC.
The RE is responsible for auditing and enforcing NERC reliability rules for 120 registered entities in three balancing authorities: SPP, Southwestern Power Administration and parts of MISO.
SPP said it was acting, in part, because of the expansion of its RTO footprint, which no longer aligns with the RE’s territory. Since 2007, SPP’s RTO has expanded to 14 states while the RE is limited to the original eight: all or parts of Arkansas, Kansas, Louisiana, Mississippi, Missouri, New Mexico, Oklahoma and Texas.
“Given that the footprints of the SPP RTO and SPP RE no longer align — due to our significant growth over the last decade and in light of further potential expansion opportunities to the west … SPP’s executives, Board of Directors and Members Committee have made the strategic decision to focus on our core functions of reliability coordination, wholesale market operations and transmission planning,” CEO Nick Brown said in a statement. “I believe this is in the long-term best interest of SPP and our members.”
SPP said NERC had agreed to terminate the delegation agreement that appointed SPP as an RE in 2007. On Sunday, the RTO’s board and Members Committee voted to give Brown authority to terminate the delegation agreement, a decision the SPP RE Trustees endorsed on Monday.
Pressure from NERC?
SPP said it will work with NERC and FERC on the transition, which is expected to be complete by the end of 2018.
SPP sources said the decision came under pressure from NERC, which wanted to end RTOs’ RE functions. Brown’s statement said the decision had come “with the support and encouragement of NERC.” NERC spokeswoman Kimberly Mielcarek told RTO Insider that NERC “supports this decision and will work with SPP to ensure a seamless transition.”
SPP’s dual role had also caused it problems with FERC, which criticized SPP in a 2008 audit for failing to ensure the RE’s independence from the RTO (PA08-2, AD09-3). The audit called for improved oversight from the RE Board of Trustees to prevent conflicts of interest.
At the time, the RE had a budget of $4.6 million, for 12.4 full-time-equivalent employees, but it only had five full-time employees, with the remaining staff performing functions for both the RTO and RE.
In response to the audit, SPP agreed to eliminate all reporting relationships between RE and RTO employees. The RE now has 24 employees and a budget of about $10.8 million.
“We are going to move on,” Brown said at Tuesday’s board and Members Committee meeting. “Each and every time we entered into [renewing NERC’s delegated agreement], the relatively small size of the RE footprint and the connection between the RTO, the RE itself and our corporate compliance business [was an issue]. It was clear to us the continued renewing of that agreement was in jeopardy.”
| NERC
When NERC first delegated compliance monitoring and enforcement authority to its REs, half of them were affiliated with registered entities, according to SPP, which said it is the only remaining organization to operate as both an RTO and RE. “When SPP dissolves the SPP RE, only one of the eight [Regional Entities] will remain affiliated with a registered entity, and no ISO/RTOs will perform RE functions,” SPP said.
Transition
Mielcarek said SPP will provide a transition plan to NERC for review.
“The 120 registered entities within the SPP footprint will be notified of the dissolution and given the opportunity to submit a written request to transfer to another Regional Entity. NERC will determine whether the transfer is appropriate based on various criteria, including geographic location, electrical boundaries and resources,” Mielcarek said.
All changes must be approved by NERC’s independent Board of Trustees, then filed with FERC for its approval. “The outcome of this intensive process will result in a more efficient and effective [Electric Reliability Organization] Enterprise and NERC looks forward to working with all affected parties,” Mielcarek said.
Brown said the transition will take time. “It’s not something that’s done overnight. A lot of coordination has to occur between the SPP RE and the audits we have underway.”
Brown said there will be “much debate in the Members Committee” about the transition to another RE, and that NERC will facilitate many of the meetings.
24 Employees Affected
The RTO said it was “committed to ensuring the continued employment” of the 24 RE employees. “There’s a lot of interest in those employees,” Brown said. “They’ve done exemplary work over the last decade and are noted as experts by a number of professional entities.”
Dave Hudson, president of Xcel Energy’s New Mexico and Texas operations, complimented the RE staff on behalf of the members: “They are very professional in a hyper-technical area, and we appreciate working with them. The world changes, but these people are very competent and have a bright future in front of them.”
Dave Christiano, chair of the RE Trustees, responded: “They’re highly educated and highly prepared. A lot of our people are certified, which isn’t generally the case with other REs. We’re working with the other REs and NERC to ensure a good future for our employees.”
Mountain West: No Impact
Mountain West Utilities map | Mountain West
SPP’s RTO footprint expanded first with the addition of the Nebraska entities in 2009 and the Integrated System in 2015. SPP is currently wooing the Mountain West Transmission Group — two investor-owned utilities; two municipal electricity providers; two generation and transmission cooperatives; and two federal power marketing administration projects covering most of Colorado and Wyoming, along with parts of Nebraska, New Mexico, Arizona and Montana — to join the RTO. Adding Mountain West would mean including in the RTO’s Tariff all the DC ties between the Eastern and Western Interconnections, except for one in Canada. (See SPP, Mountain West Members Get Acquainted.)
Mark Stutz, spokesperson for Xcel Energy’s Colorado utility, said the dissolution of the RE will not impact Mountain West’s decision on joining the SPP RTO. “It is really an issue more local to the area in which it is occurring. The function of the Regional Entity (RE) is essentially one of standards compliance and enforcement. In the MWTG footprint, that’s currently handled by the Western Electricity Coordinating Council (WECC); if [a] regional transmission organization is formed in the Mountain West, this function still would be handled by WECC.”
[Editor’s Note: Editor-in-Chief Rich Heidorn Jr. participated in the 2008 audit of the SPP Regional Entity as a member of FERC’s Office of Enforcement.]
The City of Garland, Texas, last week told ERCOT it wants to mothball a 454-MW power plant for all but the summer.
| Tom Harpool Collection, University of North Texas Special Collections
The city’s municipal utility, Garland Power & Light, said it wants to run Gibbons Creek Generating Station only from June 1 to Sept. 30 each year, according to a notification of suspension of operations (NSO) filed Wednesday. The suspension would be effective Oct. 17.
Although Garland is a Dallas suburb, the 34-year-old coal-fired unit is located northwest of Houston. The plant is operated by the Texas Municipal Power Agency.
ERCOT stakeholders have until Aug. 2 to file any comments on the NSO as part of the standard reliability-must-run review.
The ISO also said on Thursday that it has determined a Union Carbide 40-MW gas-fired generator on the Texas Gulf Coast is no longer needed for transmission reliability needs and can be retired, effective Sept. 29. Union Carbide filed its NSO in June.
Gibbons Creak Generating Station | PMelton87, Wikipedia
The cogeneration unit went into service in 2000. As a private-use network unit, it is connected to the ERCOT grid, but the load is netted with internal generation and not directly metered by the Texas grid operator.
Stakeholders are at odds with MISO over some aspects of the RTO’s new interconnection queue rules during a time when the queue is beset by “unprecedented” backlogs.
RTO staff said the sheer volume of prospective projects is creating an overwhelming definitive planning phase (DPP) study cycle this year.
| MISO
“It’s the largest queue we’ve ever had — over 200 projects,” Patrick Brown, executive director of transmission asset management, said at a July 18 Interconnection Process Task Force (IPTF) meeting. MISO is reviewing project applications and will update the list of queue projects based on study findings by the end of July.
But multiple stakeholders have asked that queue implementation details be fleshed out in joint discussions involving either the Planning Subcommittee or Planning Advisory Committee. They contend that the RTO needs to more fully vet the policy and reliability implications of moving from one iteration of the queue process to the next.
Approved by FERC early this year (ER17-156), MISO’s new interconnection rules attempt to streamline an old process that was plagued by restudies and backlogs. (See FERC Accepts MISO’s 2nd Try on Queue Reform.) MISO Manager of Resource Interconnection Neil Shah said DPP studies coming out of the MISO West region are particularly heavy this year — “more than the current transmission system can accommodate” — and schedule delays are imminent. The RTO has so far this year received 85 requests representing nearly 12 GW of possible generation from that region alone.
| MISO
“The most practical thing to do is to prepare for delays. It’s really unprecedented, and the complexity of the studies will increase. … We just want stakeholders to be aware of how much it’s going to take to study this amount of megawatts,” Shah said.
Staff argued against stakeholders that were looking to change an already agreed-upon DPP timeline.
“Let’s not beat this dead horse,” Brown said. “I think we’ve had those discussions before. It was really incumbent on the stakeholders to decide if they want to accept those risks, and they’ve agreed to those risks. Stakeholders preferred to get it started right away.” He added that discussion was laid to rest in IPTF meetings during the spring.
MISO will clear the February 2016 batch of projects from the first part of the DPP before submitting any of the August 2016 entrants, a process that stakeholders favored over merging the two groups together in order to initiate the studies earlier — even if the separated approach carries an increased risk of restudy.
Shah said stakeholders decided in spring to continue with the changeover schedule, which was initially filed with FERC.
“Based on the feedback that we’ve received so far, we’re going to continue the course on the original schedule,” he said.
Shah noted that the probability of delays is high, even without a current delay. MISO is putting more of its own resources toward the study effort, he said.
The RTO is adding an additional 14 engineers to the approximately 100-employee queue team to handle the influx of studies, according to Brown. Eight Siemens engineers are working on studies for the possible additions in the MISO West region alone.
“There’s much consternation and gnashing of teeth among my finance team right now,” Brown said. “We still think there are going to be delays no matter how many bodies we throw at it.”
Geronimo Energy’s Randy Porter applauded MISO for being able to complete its schedule of studies on time so far this year. “I’d like to copyright a term: ‘study-tsunami,’” he said.
Stakeholders asked if MISO will compare the high number of projects to anticipated load growth to see if the projects will realistically be built.
MISO “would take a step back and look at the comprehensive picture” in subsequent studies occurring further into the queue, Shah said.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees 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.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following proposed manual changes:
A. Manual 1: Control Center and Data Exchange Requirements. Revisions developed to comply with NERC reporting requirements. Transmission operators will be required to maintain certain data during outages, including bus voltages for all 345-kV stations or higher, and megawatt flows for tie lines and all lines 345 kV or higher.
B. Manual 11: Energy & Ancillary Services and Manual 18: PJM Capacity Market. Clarifies language on what is needed to qualify for exempt or bonus megawatts during performance assessment hours in PJM’s Capacity Performance construct. PJM says it needs certain data to determine how close generators follow its schedule. The data include values for economic minimum and maximum and emergency maximum.
3. Pseudo-tie Pro Forma (9:30-10:00)
Members will be asked to endorse proposed pseudo-tie agreements and Tariff and Operating Agreement revisions. The documents were developed to standardize pseudo-ties and minimize operating confusion. (See “OC Discusses Pro Forma Agreements for Pseudo-Ties, Dynamic Schedules,” PJM OC Briefs: July 11, 2017.)
4. Governing Document Revisions to the Limitation on Claims (10:00-10:10)
Members will be asked to endorse Tariff and Operating Agreement revisions to clarify the two-year limit on requests for billing adjustments.
Members will be asked to endorse updates to Manual 14B: PJM Regional Transmission Process and the Operating Agreement reflecting the change from the annual, 12-month Regional Transmission Expansion Planning cycle to an overlapping 18-month cycle beginning each September. The window for short-term projects will expand from 30 to 60 days. (See “RTEP Cycle Revisions Approved,” PJM PC/TEAC Briefs: July 13, 2017.)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions to regulation market rules on performance scores, clearing and settlements that were endorsed by the Regulation Market Issues Senior Task Force and the MRC. The revisions change the rate for substituting traditional RegA and fast-response RegD. (See PJM Regulation Compensation Changes Cleared over Opposition.)
2. Pseudo-tie Pro Forma (1:45-2:15)
Members will be asked to endorse proposed pseudo-tie agreements and Tariff and Operating Agreement revisions. The documents were developed to standardize pseudo-ties and minimize operating confusion. (See MRC item 3 above).
While PJM stakeholders were meeting last week to consider yet more changes to the Reliability Pricing Model, public power representatives took their case to Congress, telling the House Energy and Commerce Committee on Tuesday that they should be released from participating in the increasingly complicated capacity construct.
American Municipal Power and Old Dominion Electric Cooperative told the committee that FERC should allow public power utilities to fill their needs through bilateral contracts or self-supply instead forcing them to participate in mandatory capacity markets. AMP — which provides power supply and other services to 135 members in Delaware, Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, Virginia and West Virginia — also complained that PJM’s Capacity Performance rules undervalue the company’s new hydropower facilities.
AMP Senior Vice President and General Counsel Lisa McAlister and ODEC CEO Jack Reasor testified along with representatives from independent power producers NextEra Energy and Calpine, utilities Public Service Enterprise Group and Duke Energy, and demand response provider EnerNOC.
The two-hour hearing, titled “Examining the State of the Electric Industry through Market Participant Perspectives,” covered many issues. Rep. John Shimkus (R-Ill.) and ranking member Frank Pallone (D-N.J.) said the testimony would help them decide whether the Federal Power Act is in need of revisions.
PSEG made a pitch for financial support for its New Jersey nuclear plants, which Calpine and NextEra strongly opposed. Duke asked for reforms to the Public Utility Regulatory Policies Act and a “shot clock” for regulatory approvals of pipelines and other infrastructure projects.
Former FERC Chairman Joseph Kelliher, now executive vice president for NextEra, also offered his company’s answers for the questions that Energy Secretary Rick Perry asked in commissioning a study of renewable resources’ effect on the reliability of the grid. It is market fundamentals — not public policies, he said — that are the primary drivers of “baseload” plant retirements, and there is “no evidence” that those retirements are threatening reliability.
No RTOs or ISOs were represented in the hearing. They will get their chance to speak before the committee in a second hearing on July 26. But PJM was invoked frequently, and generally not favorably.
PJM Capacity Market under Fire
McAlister’s 21-page written testimony — more than twice as long as any other witness’ — reiterated public power’s longstanding complaints with PJM’s capacity construct, calling it a “complex rules-driven administrative mechanism” that “relies on such distinctly non-market features as an artificial demand curve, price caps and minimum offer price requirements, and obstacles to competition from certain types of resources.
“RPM is a ‘market’ in name only,” she continued. “And, as time has gone on, fewer and fewer PJM market participants use that term to describe it.”
ODEC also criticized RPM, saying its experience “has been mixed at best.”
Reasor quoted from FERC’s April 2006 order approving RPM. “After [load-serving entities] have had the opportunity to procure capacity on their own, it is reasonable for PJM to procure capacity in an open auction at a time when further delay in procurement could jeopardize reliability,” FERC said, adding, “This, however, should be a last resort.”
Although the annual capacity procurement is still called the Base Residual Auction, “repeated and significant design changes have made RPM more complex and costly and have undermined the ability of load-serving entities to use their resources to meet their capacity obligations,” Reasor said.
The 2016 BRA was the first PJM capacity auction with no rule changes from the prior year, following 24 significant FERC filings to revise RPM between 2010 and 2016, Reasor said, quoting PJM. The last major change, the introduction of Capacity Performance, imposes “onerous performance requirements” on capacity resources, he said.
New Hydro Dissed by CP
McAlister also complained about CP, saying it undervalues the $3 billion AMP spent to install 300 MW of hydroelectric facilities on existing dams on the Ohio River because the projects cannot guarantee continuous, yearlong operation. “This is the case because AMP cannot control the river flows and cannot practically back up the hydroelectric plants with an alternative generation resource,” McAlister said. “In making PJM’s capacity construct less flexible, CP also has made it less capable of integrating the diversity of resources that may be an element of implementing important state policies.”
McAlister said PJM “needs a resource adequacy construct that is robust enough to withstand the effect of external events without the need to adopt another set of complex rule changes in response to each event.”
She and Reasor said LSEs should be permitted to fulfill most or all of their capacity needs through bilateral contracts, with the BRA relegated to a truly residual auction to fill any shortfalls. (See related story, PJM Stakeholders See Capacity Auction Flaws, Offer Solutions.)
As a “second-tier alternative,” McAlister said, public power’s ability to self-supply their own loads should be restored by reducing the role of the minimum offer price rule (MOPR).
Transmission Costs
AMP also complained about transmission costs, saying four of its members’ transmission zones have seen annual revenue requirements double or triple between 2009 and 2016.
AMP’s and ODEC’s complaints regarding the transmission owners’ handling of supplemental projects — those not required for compliance with PJM’s reliability, operational performance or economic criteria — prompted FERC last August to issue an order to show cause finding that the TOs’ procedures were not in compliance with FERC Order 890 (EL16-71).
FERC said the evidence indicated that some TOs are “identifying — and even taking steps toward developing — supplemental projects before providing any opportunity for stakeholders to participate in the development of those projects through the PJM [Regional Transmission Expansion Plan] process.”
The order resulted in a hiatus in a stakeholder initiative, the Transmission Replacement Processes Senior Task Force, pending the TOs’ response. Although the TOs insisted they are in compliance with Order 890, they proposed a Tariff amendment providing additional detail on supplemental projects. FERC didn’t rule on the TOs’ response before losing its quorum in February.
“AMP supports appropriate transmission infrastructure build-out to replace aging infrastructure,” McAlister told the House committee. “However, there needs to be more transparent transmission planning, equitable treatment, better oversight to ensure the most cost-effective and efficient grid expansion, and rates of return that reflect current economic conditions and risks.”
AMP asked Congress for “enhanced” oversight of FERC “to ensure that [the commission] is responsive to the real needs of consumers” by making low costs “a central part of the RTO mission, in addition to promoting electric system reliability.”
McAlister also said Congress should ensure that RTO governing boards “are truly representative and open [and] transparent” with open board meetings. While the boards of MISO, SPP, ERCOT and CAISO meet in open session, PJM’s board meets in private, as does ISO-NE’s and NYISO’s.
The hearing also considered proponents and opponents of subsidizing nuclear plants. Tamara Linde, PSEG’s executive vice president and general counsel, repeated the company’s threat to retire its 3,500-MW Salem and Hope Creek nuclear plants in southern New Jersey. The plants, which are licensed until at least 2046, produce about 45% of the state’s electricity.
Linde said FERC should order PJM and other RTOs to “immediately” change their market rules to “preserve the diversity and resiliency of the nation’s electric generation resource mix.”
“Markets weren’t designed to drive to fuel diversity as an outcome, because fuel diversity in the generation fleet was always presumed,” she said.
Linde also said the U.S. nuclear supply chain should be considered “critical infrastructure, just as we regard our national highway system, electric grid and drinking water.”
Opposing nuclear subsidies were NextEra’s Kelliher and Calpine’s Steve Schleimer, senior vice president for government and regulatory affairs. Schleimer said competitive markets are threatened by both the zero-emission credits for nuclear plants in New York and Illinois, and New England states’ long-term procurement of renewables.
“If not addressed, out-of-market subsidies will undermine competition, investment will dry up, and these states will be back in the business of mandating when, where and what type of new generation will be built through long-term ratepayer guarantees, which is exactly the structure we moved away from several decades ago,” he said.
“A ‘hybrid’ market, where a state relies in part on the competitive wholesale electricity market to meet its resource needs, but also retains the right to select and subsidize preferred generation resource types to meet certain public policy goals, does not work and destroys all new competitive investment,” Schleimer said.
CAISO’s Lesson
He said the risk is playing out in CAISO, where he said the state’s “long-term contracting practices have decimated the competitive market.”
“It has led to the paradox that while retail rates are amongst the highest in the country as a result of these contracting mandates, wholesale prices are so low that the economic viability of the remaining generation that is dependent on competitive wholesale markets (generally existing conventional generation resources acquired or built when the market was competitive) is increasingly threatened.”
Alex Glenn, Duke’s senior vice president for state and federal regulatory legal support, had five requests to Congress, including swift confirmation of FERC nominees; the retention of the federal income tax deduction for interest expenses; “a reasonable ‘shot clock’ for actions on permit applications” for critical infrastructure projects; and a rewrite of PURPA to eliminate above-market must-take purchase obligations.
Glenn also said Congress should amend the SAFETY Act “to expressly include cyberattacks, and improve the process to obtain a security clearance so that we can increase the information-sharing capabilities between public and private entities.” Including cyberattacks under the third-party liability protections in the act would allow utilities and first responders to help recovery from an attack without the threat of “of protracted lawsuits in multiple jurisdictions,” he said.
In contrast to Duke’s lengthy wish list, Kenneth D. Schisler, vice president of regulatory affairs for EnerNOC, had only one request. Schisler thanked federal policymakers for removing market barriers to DR and said “it is vital” that FERC find a way to maintain competitive markets while respecting state policies. “Our only ask here today is that you continue to recognize demand response and its importance to our national energy strategy,” he said.
VALLEY FORGE, Pa. — PJM’s Capacity Construct Public Policy Senior Task Force has been working at a torrid pace to develop potential rule changes in time for next year’s capacity auction.
After little more than four months of meetings, PJM and stakeholders have offered four proposals to fix what many see as flaws in the RTO’s capacity construct. The main issue is how to accommodate state actions — such as energy credits or tax incentives, which subsidize certain generation types — without allowing them to influence clearing prices.
The RTO envisions a two-stage auction in which the first stage includes subsidized units and creates a “suppressed capacity price” using PJM’s standard variable resource requirement (VRR) demand curve. The second stage replaces subsidized units with a “reference price offer reflecting what would be a competitive offer from a unit of that type and vintage.” This would create a higher “restated price” more in line with pure competition that all cleared units would receive, unless states instructed PJM to pay its subsidized units less. Units that didn’t clear under the “suppressed” price would not receive capacity payments, even if they clear under the “restated” price.
| NRG
LS Power and NRG Energy responded at the task force meeting July 17 with proposals to tweak the two-stage approach. Both were designed to address those units that slipped between the auctions, which NRG referred to as “in-between” units. LS took the route of adjusting price, while NRG focused on adjusting quantity.
LS calls its proposal the “clearing price impact election model.” It factors the output of subsidized units into the second stage, resulting in a lower subsidized clearing price. Generators would have to elect when they submit their bids whether they would accept a lower subsidized price, which PJM would estimate before the auction. Those who won’t accept the lower price don’t clear, and the final clearing price would be adjusted upward as their output is eliminated from the supply. This would discourage units from creating price suppression by bidding low, LS argues.
NRG’s approach would also determine prices with and without subsidized units. Subsidized units would receive the subsidized price, and unsubsidized units would receive the unsubsidized price. The “in-between” units that clear the auction in the unsubsidized price but not in the subsidized price would clear and receive the unsubsidized price. The quantity of all offers would be reduced proportionally to ensure the entire auction cost is no higher than the total for the auction using the unsubsidized price.
Other Perspectives
Two other stakeholders took drastically different approaches.
Exelon, which has been battling for more than a year to secure state subsidies for some of its nuclear fleet, argued why such subsidies shouldn’t be mitigated in PJM’s auctions. More than 10 GW of resources “receive longstanding state support to enter/remain the market,” Exelon says, with the largest category being small- to medium-sized coal plants in regulated states.
“Resource adequacy objectives have been met at a reasonable cost despite the material impact on the marginal clearing price,” according to Exelon’s report. “Mitigation is unnecessary.”
“This is a very complex topic and we tried to bring some data and performance results into the conversation, realizing that other stakeholders may have different perspectives,” said Exelon’s Sharon Midgley, who presented the proposal.
Last Tuesday, the second day of the two-day task force meeting, American Municipal Power called for a smaller role for the Reliability Pricing Model, with public power permitted to meet most of their capacity needs through long-term bilateral contracts. AMP’s Ed Tatum argued that RPM is an “administrative construct … not a market,” and that PJM and its stakeholders “have to stop focusing on price and let a market do its thing.” Since 2010, PJM has made at least 27 major filings changing RPM, he said.
| Exelon
AMP’s plan would hinge on annual determinations of capacity obligations for load-serving entities, with a capacity auction several months before the delivery date, rather than three years. It would also eliminate the single clearing price created by the VRR curve in favor of a mechanism to match individual buyers and sellers. (See related story, Public Power Takes its PJM Gripes to Congress.)
| NRG
Several RPM structures would be maintained, such as resource must-offer requirements, the RTO reliability requirement, demand response participation and the Capacity Performance system of bonuses and penalties. The group also proposed a penalty on LSEs that fail to secure necessary capacity.
Stakeholders from both supply and demand pushed back, largely concerned that the plan would impede price transparency.
“Those customers who are signing up specifically to hedge their capacity costs, if they don’t know what the price that they’re paying is, that’s very difficult for them to hedge,” EnerNOC’s Katie Guerry said.
Joe Bowring, PJM’s Independent Market Monitor, had a much simpler solution.
“You can’t be partly regulated and partly not. You have to choose, and states have a whole range of options,” he said. “If states want to take it back [and fully regulate the industry], that is absolutely within their authority. What they shouldn’t do is take actions that are not in their authority. … If you subsidize two or three particular units … you’re suppressing the price of energy compared to what it would have been and you’re putting other units that are now economic at risk. That’s why I continue to repeat that subsidies are contagious.”
He said there’s no sense in “trying to work out complicated ways to make subsidies work in markets when they really can’t.”
“To me, the problem that has been identified is that competition is working,” Bowring continued. “Competition is a nasty business. Competition puts people out of business on a regular basis. I think it would be very difficult for the PJM markets in their current form to adapt to any more fully regulated states. … It would mean a significant change because the current structure of fully competitive markets is not compatible with a mix of generators with revenues based on cost-of-service regulation and generators with revenues dependent on markets.”
After the meeting, Bowring submitted recommendations that provide a definition for subsidies and call for developing an extended minimum offer price rule for all subsidized units that would be reviewed annually.
The task force has another two-day session planned for Aug. 2-3, at which Bowring’s recommendations and an update to the proposal from LS will be discussed. Other meetings are scheduled for Aug. 23, Sept. 11 and Sept. 26. The task force’s issue charge calls for any results to be delivered by the end of the year.
