FOLSOM, Calif. — CAISO is moving ahead with major modifications to its congestion revenue rights (CRR) auction even as some stakeholders urge a deeper look into the possible detrimental effects of the plan before it goes to FERC.
CAISO defended its approach during a Tuesday forum on the CRR process. Some commenters are saying the ISO is taking an overly simplistic view of the issue: whether the CRR auction is a legitimate hedging mechanism or a process that forces ratepayers to become unwilling participants in losing transactions.
CAISO’s Department of Market Monitoring has become increasingly outspoken about what it calls auction “payment deficiencies” of more than $500 million — the difference between auction proceeds and payouts, which are based on day-ahead market congestion. But some market participants are protesting that the ISO is ignoring other benefits from the transactions. The debate over financial transmission rights is also occurring in other ISOs and RTOs. (See Market Monitors Bring FTR Complaints to Congress.)
CAISO discussed reforms throughout last year and unveiled its initial reform proposal at the beginning of this month. (See CAISO Overhauling CRR Auctions.)
The ISO intends to eventually restrict CRR transactions to only those needed for physical transfer of energy, and limit CRR source and sink pairs to nodes between generators and interties, as well as between trading hubs, loads and interties. It has also proposed to decrease the amount of system capacity released in the CRR auction process from 60% to 40% in the long-term allocation, and 75% to 45% for the annual allocation and auction process — a move intended to reduce overselling of transmission capacity. The ISO would also eliminate disclosure of certain modeling information and align existing outage reporting rules with the annual CRR process.
Track 1 of the effort consists of measures to be put in place for the 2018 auction process this summer, slated for March approval by the Board of Governors. Track 2 will include more significant changes, targeted for board approval sometime in the middle of the year, CAISO Market Design Manager Brad Cooper said in a presentation.
Kolby Kettler, of energy and commodities trader Vitol, has questioned the proposal since it was introduced. On Tuesday, he said the plan could introduce detrimental effects and new risks that CAISO has not considered.
“Other ISOs have also gone down this avenue, looking at removing locations, and have backtracked” because of revenue loss to the market, he said. He urged CAISO to focus on “fixing the model, and not focus on removing what could be a legitimate hedging activity or valuing congestion.”
“We are working to try and quantify the benefits of auction CRRs to the broader market,” Cooper replied, adding that “this isn’t the net effect … because CRRs have a benefit to the bilateral market.”
Speaking for the Western Power Trading Forum, Ellen Wolfe contended that CAISO was operating from a narrow viewpoint. She said the ISO has “narrowed in on the premise of the purpose of the CRRs being this physical hedge,” but that certain hedges might be beneficial for physical supply in ways the ISO is not considering.
“You build these proposals based on that particular premise — it presents a very narrow viewpoint of the world — and present anything outside of that viewpoint as not legitimate,” she said. “It is at least beneficial … to acknowledge that not everybody agrees with your premise.” Previously, there was never a sense that CRRs should be made available only to generators serving a load, she said.
“We are doing all we can to understand the uses,” Cooper said, but the auction revenues are far short of what CRRs are paying. “Sure, we would be eliminating combinations to allow for every type of conceivable hedging opportunity,” but “I think we are striking a reasonable balance,” he added.
CAISO is taking comment on its CRR proposal through Feb. 28.
As far as PJM transmission owners are concerned, the customer doesn’t always know best. They lack the institutional knowledge of the TOs, who have been operating their systems for decades and are responsible for their performance.
PJM transmission customers agree that they don’t have the information the TOs possess. But some are trying to change that imbalance, saying they are no longer willing to pay for replacing aging infrastructure system without assuring themselves that the spending is necessary.
How much more information the TOs will be required to share could be decided at today’s FERC meeting. The commission is scheduled to release a decision on its 2016 show cause order that questioned whether TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation,” as required by Order 890 (EL16-71). (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
The commission is also scheduled to address the TOs’ proposed Tariff Attachment M-3, which they developed to codify the “additional detail and transparency regarding the process for planning supplemental projects” that they’ve agreed to (ER17-179). (See PJM Demands Agreement on Tx Replacement Definitions.)
RTOs Provide Customer Forum
For most of their existence, TOs have had only to persuade state and federal regulators that their infrastructure plans were necessary, under a monopoly structure that entitled them to cost recovery and a margin of profit. The development of RTOs and ISOs has given their customers a forum to voice concerns and seek influence over transmission planning.
In PJM, American Municipal Power has made controlling its transmission costs a primary focus. Supported by several other RTO members — fellow transmission customers, state consumer advocates and merchant transmission developers — AMP has pushed the issue to confrontation on multiple fronts, including a stakeholder task force focused on end-of-life issues for transmission infrastructure. (See AMP Presses AEP, PSE&G on Transmission Projects.)
The Transmission Replacement Process Senior Task Force (TRPSTF) became a flashpoint almost as soon as it was proposed in January 2016. TOs argue that PJM and FERC rules give them sole discretion over how to maintain their assets — including when and how to replace them. The task force went into a 10-month hiatus after FERC issued its show cause order but reconvened after PJM stakeholders reinstated it last year.
More Transparency Sought
AMP and Old Dominion Electric Cooperative said they have been concerned about transparency in the planning process for quite some time.
“I don’t know if we had a big bang or if we had a slow burn,” AMP’s Ed Tatum said in an interview with RTO Insider. “We just kept asking more questions. … That gave us some traction to continue to ask questions.”
Both sides acknowledge that infrastructure, at some point, needs to be replaced. But the customers argue they aren’t provided enough information to independently evaluate whether proposed replacements are necessary or excessive. “I feel there should be adequate information for us to determine what is needed,” Tatum said.
AMP and ODEC argue that TOs are incentivized by their formula rates to build as much as possible and that regulators’ oversight is not adequate to corral the impulse.
“To me, it’s more of a check and a balance: Before they start replacing something, does it make sense?” ODEC’s Mark Ringhausen said. “Maybe that’s a concern that some of the TOs have: [that customers will] figure out that we’re replacing more facilities than they really need to.”
They point to a sudden rise in supplemental transmission projects, which are projects developed by TOs for their own transmission zones to address their own planning needs. They don’t have to address any PJM criteria, nor do they require the RTO’s sign-off to begin work.
Through 2012, according to a study done for AMP, PJM had planned or in service $21.3 billion in baseline and network upgrades — which are subject to detailed review by the RTO — versus $6.8 billion of transmission-owner identified (TOI) and supplemental projects. Since 2012, the $11.6 billion in baseline and network upgrades have been exceeded by $12.7 billion of TOI/supplemental projects.
“There are more projects outside of the PJM planning process than there are inside,” Tatum said.
“Of the 270 supplemental projects in 2017, when presented at their respective first reads [at Subregional RTEP Committee meetings], 181 of the projects were already in a stage of development ranging from engineering to 100% complete, with five projects already in service at their first reads,” the customers said in a 61-page recounting of their arguments filed on Tuesday. “At the second read, 205 out of 270 proposed supplemental projects were beyond the conceptual/scoping development phase, with nine already in service. Said another way, 76% of supplemental projects were presented to stakeholders in the SRRTEP meetings at a stage of development where meaningful input is unfeasible at best.”
Customers believe TOs have used these opportunities to bypass the stakeholder process and go straight to state and federal commissions, where they say they maintain longstanding political influence, as their best bets for revenue growth. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
“I think it’s pretty simple economics. They’re not making a whole lot of money on generation right now, and they’re getting [returns on equity] on transmission in the 10 to 12% [range]. We don’t blame them,” AMP General Counsel Lisa McAlister said.
“Part of the reason why [customer input is] so important is because there’s not a lot of other regulatory oversight, and when it does happen, it’s too late in the process to be meaningful,” said McAlister, who signed AMP’s filing. “There aren’t a whole lot of other stopgaps to help.”
In its filing Tuesday, which asked the commission to reject Attachment M-3 and order further changes to achieve compliance with Order 890, the customers said FERC should require TOs and PJM to:
Record and post all questions and answers from proposal reviews;
Provide the power flow study details, including a description of the violations or issue identified;
Provide more detailed descriptions of the proposed facilities, including descriptions and costs of the assets being retired, installed or replaced; and
Provide adequate time for review and analysis.
PJM’s subregional transmission expansion plan process “has no provision to validate a TO’s need for supplemental projects nor the prudency of the project,” the coalition said.
TOs’ Response
The customers’ requests ignore PJM’s function on supplemental projects, says Exelon’s Gloria Godson.
“PJM’s process is a planning process, not a prudency review,” Godson said in an interview with RTO Insider. The correct venue for cost complaints is at FERC and state commissions, not PJM, she said.
To best understand the conflict, Godson said, think of TOs as car manufacturers and their networks as their own unique vehicle that they lease to customers. Customers get to use the car for their needs and must pay for improvements and maintenance, but ownership, knowledge about and ultimate responsibility for it remain with the manufacturer.
Customers want to understand the car’s engineering so well that they can independently confirm the need for the expenses the owners want them to incur. But the owners fear customers are more focused on cost because they’re not on the hook for the car’s reliability.
PJM, in Godson’s analogy, is the company that builds and maintains roads. But the RTO can’t tell TOs what tires to install on the car or when to replace the radio, she said, any more than it can tell TOs how much that work should cost.
In a combined statement to RTO Insider, PPL, Public Service Electric and Gas (PSE&G), Exelon and Duquesne Light said replacement costs have increased in response to new obligations, such as higher security demands and increased efficiency and reliability standards.
“Shared final decision-making with a diverse set of stakeholders each with differing priorities would negatively impact the safety, reliability, security and efficiency of the transmission network. It would also lead to lack of clarity as to who has the responsibility for the impact of adverse events,” the TOs said.
Order 890, the TOs said in their October 2016 response to the order to show cause, “affirmed that the ultimate responsibility for planning remains with transmission providers and that it was not requiring transmission providers to engage customers in the transmission planning process on a ‘co-equal basis.’”
Godson pointed to her experience at Potomac Electric Power Co. (Pepco) with the failed Mid-Atlantic Power Pathway project as an example of regulators’ exercise of cost discipline. Pepco attempted to recover $87.5 million in costs after the project was canceled by PJM, but intervenors protested and FERC eventually approved a $80.5 million settlement (ER13-607).
No Bright Line
It’s not possible, TOs say, to develop a standardized way for customers to replicate the analysis that they would be able to endorse because it would require modeling so detailed and exact — on variables ranging from terrain and weather to population density, local regulations and load types — as to be impractical, along with institutional knowledge that they say only exists at the TO.
“There is no bright-line criteria for determining when an asset should be replaced, as it is based upon a variety of factors that require engineering and operational judgement,” the statement said.
“A company may be willing to take a different type of risk in a rural area than they may be willing to take in Washington, D.C., for example,” Godson added. “That goes from one TO to another, so it’s … not possible to have a cookie-cutter approach to system design. … My question would be, for what basis? PSE&G knows their system better than anybody can. … This is what they do for breakfast, lunch and dinner.”
More can be Done, Customers Say
Customers acknowledge the issues but say there’s more that can be done.
“There’s judgment to this, but those are discussions that need to happen,” Ringhausen said. “They need to present us enough information that we can understand their criteria.”
“One of my large concerns with this is [the industry] creating the exact same situation we’re in now for the next generation down the road,” AMP’s Ryan Dolan said. The transmission infrastructure was largely built at the same time, and TOs are “in a mad rush” to replace everything at the same time. Dolan argues that with some foresight and consideration, the replacements, and their costs, could be rolled out over time.
“Should we have a long, sustained capital investment?” he asked.
“TOs don’t have anything that predicts the longevity of assets. … Age is simply a bucketing mechanism, but whether and when an asset is actually replaced depends on the condition of that asset,” Godson responded. “So, you may have a transformer that is relatively newer, but if it begins to [break down], you cannot defer maintenance [just] because it’s not old enough. Conversely, there are assets that are 70 years old and still going strong. So it depends on the condition and performance of the asset.”
While TOs’ primary strategy is monitoring and replacing based on condition and performance, there are some times when equipment targeted for replacement can be addressed while repairs are being made to infrastructure nearby.
Improvements
TOs argue they have worked to improve information sharing in the monthly meetings that focus on PJM’s Regional Transmission Expansion Plan, as documented in Attachment M-3. “The PJM process is far and away the most transparent of any process in the country,” Godson said.
Tatum contends the sides are “fairly close” and that a solution to the dispute “doesn’t need a quantum shift.”
The TOs disagree with the magnitude of the change they say AMP and its allies are requesting.
“AMP’s proposal that PJM and the PJM stakeholders take over the TOs’ responsibility for asset replacement and managing the supplemental project planning process violates the [Consolidated Transmission Owners Agreement] and would breach a fundamental contract that forms the basis upon which TOs joined PJM,” the TOs said. “PJM does not have the expertise, experience or resources to take over the TOs’ asset management function. PJM has stated repeatedly that they do not consider this an appropriate role for PJM.”
CARMEL, Ind. — MISO is weighing how it can improve its interregional process and joint operating agreement with SPP to make it easier to develop cross-seams projects that have so far remained elusive.
“The assumption is the coordinated system plan is not setting us up for success,” Eric Thoms, MISO manager of interregional planning and coordination, told stakeholders at a Feb. 14 Planning Advisory Committee meeting.
Planning staff for both RTOs have agreed to meet this spring to devise ways to improve their joint study process.
Thoms said MISO is considering lowering hurdles for interregional projects, including removing the $5 million cost threshold and eliminating the joint model study requirement, which he said is unnecessary when the RTOs’ separate regional evaluations can adequately examine prospective interregional projects.
He also said the RTOs might identify more joint benefit metrics that could better illustrate the value of potential transmission projects and clarify to stakeholders the process for approving interregional projects.
However, some stakeholders said the RTOs must first address their disparate transmission usage charges before working toward interregional project approval.
“I’m glad to see MISO is trying for constituency between seams, but MISO and SPP have incompatible [unreserved usage charges],” said Minnesota Public Utilities Commission staff member Hwikwon Ham. Until the RTOs have comparable transmission usage charges, interregional projects will be difficult to approve, Ham said.
Xcel Energy’s Drew Siebenaler agreed the RTOs must discuss transmission service charges and resolve the issue of MISO consistently bearing more costs for potential projects that stand to benefit both sides of the seam.
Adam McKinnie, chief economist with the Missouri Public Service Commission, asked that the charges not be the lone hang-up in approving a possible near-term interregional project. Thoms promised to return to the PAC in April to further discuss the topic.
The next Interregional Planning Stakeholder Advisory Committee meeting will be held Feb. 27. Officials from both RTOs plan to present a more detailed coordination plan during the meeting.
CARMEL, Ind. — MISO will expedite review of a proposal to interconnect Foxconn’s massive electronics plant planned for southeastern Wisconsin months ahead of the RTO’s usual year-end approval schedule, stakeholders learned Wednesday.
The $140 million interconnection project to plug Foxconn’s $10 billion plant into We Energies’ network will move ahead “as needed to meet the December 2019 in-service date,” Lynn Hecker, MISO manager of expansion planning, said at a Feb. 14 Planning Advisory Committee meeting.
Foxconn manufacturing plant in the Czech Republic | Syner
American Transmission Co. submitted the request for accelerated approval late last year, insisting that its proposed project cannot wait until usual approvals at the end of the year as part of MISO’s 2018 Transmission Expansion Plan. ATC has proposed constructing a 14-mile, 345-kV transmission line; a new 345/138-kV substation; and new underground 138-kV lines to connect the substation to a smaller Foxconn-owned substation near the plant. (See MISO Seeks Stakeholder Input on Foxconn Decision.) MISO’s decision was based on ATC’s forecasted load of 230 MW, although Foxconn says there’s potential for campus expansion at the site, possibly adding another 200 MW of load.
Stakeholders had little to say about the project, although some asked the RTO to make more widely circulated announcements when it wraps up expedited review studies and when it plans to announce expedited decisions.
New York’s Integrating Public Policy Task Force (IPPTF) on Monday debated a proposal seeking to align the state’s effort to price carbon with the Regional Greenhouse Gas Initiative. It also discussed an alternative to NYISO’s capacity market.
Representatives from the Long Island Power Authority (LIPA) and National Grid made presentations as part of the ongoing process to develop a straw proposal for pricing carbon into the state’s wholesale electricity market, a joint effort by NYISO and the state’s Department of Public Service (17-01821) that aims to deliver a workable plan by year’s end.
The IPPTF’s work plan includes five issue tracks: 1) straw proposal development; 2) wholesale energy market mechanics and interaction with other wholesale market processes; 3) policy mechanics, such as setting the carbon charge; 4) interaction with other state policies; and 5) customer impacts. (See NYC, Goals Dominate Talk on Carbon Pricing.) The effort is still in the first track, slated to conclude March 19.
Regional Circuit Breaker
During his presentation, LIPA Director of Power Markets Policy David Clarke asked that “NYISO and DPS think about the carbon abatement cost curve throughout the RGGI region, what it might look like, what it might cost to buy and retire allowances along the curve and how far we might go to narrow differences by doing so, especially considering the roles of the cost-containment reserve.” The RGGI reserve contains allowances only released if allowance prices exceed predefined levels.
New York could reduce its carbon emissions at a lower cost by drawing on the broader region and a wider geographic set of abatement alternatives, Clarke said.
Projected RGGI allowance prices in constant 2015 and nominal dollars | ICF
“RGGI has a 10-million-ton reserve, priced in 2025 a little over $17 a ton. Essentially, it’s a circuit breaker,” Clarke said. “So RGGI states have agreed to this circuit breaker, a price increase they can live with if the market’s carbon price went too high.”
LIPA considers the state’s Clean Energy Standard (CES) goals — principally, an 80% emissions reduction by 2050 — as a starting point for pricing carbon and wants NYISO to consider an approach that increases the state’s carbon prices to the RGGI cost-containment reserve price. The power agency noted that the draft 2017 Policy Scenario Overview, prepared by ICF International for RGGI in June 2017, pointed to a “wide range” of projected 2025 allowance prices, “the lowest of which accompany high renewable build-out scenarios, but most are well below $17/ton for 2025.”
CES Impact on RGGI Prices | The Brattle Group
Clarke noted that, in The Brattle Group’s report on the social cost of pricing carbon in New York, the “starting point was a $40 adder above the assumed $17 price, so they were looking at $57-58/ton as the carbon adder.”
“The Brattle proposal is to take the carbon price and raise it into the marketplace and get some marketplace reductions, and it raises it quite a lot,” said Mark Reeder of the Alliance for Clean Energy New York. “And [LIPA] seems to be proposing as an alternative to that — [that] New York retires RGGI allowances and raises the price in the market for carbon that New York sees. But it’s not just New York; it’s everybody else [that sees a higher price], and it’s an alternative way of getting the market to see a higher price of carbon.”
Clarke agreed that was “a more or less” accurate summary of LIPA’s thinking.
“We observe that the RGGI prices are likely to trade well below the cost-containment reserve level if nothing changes,” Clarke said. “And from a loads perspective, buying and retiring allowances below this price can be significantly less expensive than the average cost loads would pay under an approach that sets a carbon adder at the social cost of carbon.”
Under current regulations, any entity, including a state or load-serving entity, can set up an account to buy allowances. RGGI regulations also provide for retiring allowances from voluntary reductions, so there are a couple mechanisms to buy or retire allowances up to the cost-containment reserve price, Clarke said.
Alternative Market Design
Ben Carron, National Grid’s senior analyst for regulatory strategy and integrated analytics, presented the company’s Dynamic Forward Clean Energy Market (DFCEM) concept, an alternative to the capacity and renewable energy credits markets in New York. Under the idea, the state would use an auction to procure the clean energy attribute from a resource, but not the energy itself. The model is designed to incentivize development of new clean energy resources and retain existing ones in order to reduce emissions.
Carron noted that “the concept is being discussed in the [Integrating Markets and Public Policy] process in New England,” but he emphasized that he was speaking on behalf of National Grid and not the other consortium members that created it. (See NECA Panelists Talk Carbon Pricing, Northern Pass.)
“We share similar concerns to those presented last week by the city of New York, which is that this needs to be considered on an economy-wide scale,” Carron said.
Locational Incentives for Clean Energy | The Brattle Group
While the task force is only addressing how to harmonize wholesale energy markets with public policies in the energy sector, Carron said a wider approach could avoid creating perverse incentives and ensure that stakeholders understand how it is going to interact with other components of the state’s energy plan.
“Doing some upfront work to establish the cost of carbon abatement in each sector would be a useful exercise for policymaking in all sectors and would inform the potential for leakage across sectors in this effort,” Carron said.
Reeder said the DFCEM appeared similar to New York State Energy Research and Development Authority auction processes for obtaining renewable resources, in which one Tier 1 REC represents the energy production of 1 MWh.
“Ostensibly, that achieves a similar outcome if I think about the CES objective [of] around 50% renewables by date X,” Reeder said. “So how would this interplay with what NYSERDA does right now? Is it a complement? Is it a supplement? Would it essentially obviate the need for NYSERDA to do what they do now?”
“I think that it might obviate the need,” Carron said. “We should create a wholesale market solution that accomplishes as much of what we’re setting out to do with public policy as possible.”
Track 2 Issues and Scheduling
The task force also reviewed a plan for Track 2 of its work, which will deal with wholesale energy market mechanics — including “carbon leakage” and how to measure emissions — and interaction with other wholesale market processes.
The plan lays out Track 2 meetings from April to July before the suggested Aug. 1 deadline for draft recommendations. The joint staff will present frameworks for Track 2 issues of each meeting and also left some meeting dates open to resolve thorny issues — such as leakage — that may require additional discussion.
| IPPTF
Representing New York City, Couch White attorney Kevin Lang expressed concern about transmission being slated for discussion on July 30, just two days before the deadline for draft recommendations.
“Waiting until the end of July to talk about transmission is way too late,” Lang said.
IPPTF co-chair Nicole Bouchez, NYISO market design specialist, said the task force would consider earlier discussions on the subject but that it did not foresee the draft recommendations covering every issue.
In addition to transmission, Track 2 will also deal with leakage and resource shuffling; emission rates for generators; carbon shadow price; carbon charge implementation; emission rates for distributed energy resources and demand response; fuel blends; how much transparency is available; the mechanics of allocating carbon revenues; credit implications; capacity market implications; and bilateral arrangements.
The task force next meets Feb. 19 at NYISO headquarters.
Some energy resource developers in California say CAISO needs to change its interconnection rules to prevent financially unviable projects from lingering in the queue and affecting more sound projects.
CAISO’s annual Interconnection Process Enhancements (IPE) process is becoming increasingly complex as the state’s generation mix changes, with renewables and storage comprising the vast majority of projects currently in the queue. The ISO outlined its 2018 IPE in an issue paper last month. (See CAISO Launches Interconnection Initiative.)
The majority of generation projects in the CAISO interconnection queue are renewables.
As part of the initiative, CAISO asked for comment on whether it should alter its Transmission Plan Deliverability (TPD) allocation, which establishes the amount of additional transmission capacity needed for projects to achieve deliverability and determines generators’ cost responsibility for network upgrades costs. Projects allocated sufficient TPD receive reimbursement for their upgrades. CAISO uses a point system to allocate TPD based on project status, including the status of project financing, power purchase agreements, regulatory approvals, land acquisition, and other factors.
CAISO’s current process provides interconnection customers with two annual opportunities for earning TPD allocations following Phase II interconnection studies and after one year of parking in the queue. Under revisions filed with FERC, which the ISO says are likely to be approved, a third annual opportunity for a TPD allocation will be made available to interconnection customers following a second year of parking. Projects that don’t qualify for a TPD allocation following the three opportunities must convert to energy-only status — making them ineligible for resource adequacy payments — or withdraw from the queue.
In its comments to CAISO, Southern California Edison (SCE) said it opposes allowing projects to remain in the queue indefinitely and to have endless opportunities to apply for deliverability status.
“Such projects remaining in the queue open-endedly without making progress towards their commercial operation negatively affect other active projects,” the company said.
SCE said projects not allocated TPD by the end of the second parking period should be required to execute the agreement and proceed as energy-only or be suspended, allowing for a three-year period during which they retain priority for TPD allocation. Two parking periods and a three-year suspension should be adequate, the utility said.
Differing Opinions on TPD Allocation Changes
Utility-scale developer First Solar said that forcing projects into “energy-only” status and large forfeiture amounts that become due if a project withdraws might incite developers to choose energy-only status rather than depart the queue. The company said the issue is compounded by a lack of transparency of available deliverability at interconnection points on the CAISO grid.
“Deliverability is critical for marketing a project, as energy-only projects currently are less appealing due to their lack of resource adequacy attribute and are therefore less competitive in procurement,” First Solar said. “We ask the CAISO to address several issues that prevent interconnection customers from being allocated or retaining deliverability, as well as issues that have impacts on others in the queue.”
CAISO resource developers have competing views of how interconnection policies should be overhauled.
But the state’s Office of Ratepayer Advocates (ORA) said it did not support changes to the current TPD allocation process that allows three opportunities for TPD allocation, rather than allowing projects to remain in the queue indefinitely.
“Changes in the queue procedures should only be considered for resources that meet project area needs, support state resource targets or CAISO-controlled grid needs, such as resources that can respond to grid demands throughout the day and/or provide additional services in addition to energy,” ORA said.
The California Wind Energy Association said that with the third allocation option on file at FERC, “there is no need to tinker with the TPD allocation process. We suggest that this IPE element be tabled.”
Independent transmission company ITC said it supports inclusion of the possible TPD changes in the scope of the 2018 IPE stakeholder initiative as part of its “broader support” for studying the impacts of allowing projects with potentially limited commercial viability to remain in the queue and seek TPD allocation.
ITC also recommended the initiative further examine “how identified impacts of an interconnection request on neighboring systems are coordinated and mitigated” to “consider additional clarifications to Affected System practices.”
The company pointed to FERC’s recent order on a complaint by the Environmental Defense Fund regarding MISO, PJM, and SPP Affected System studies. Earlier this month, the commission ordered a technical conference after finding the RTOs’ tariffs and joint operating agreement do not fully explain the guidelines and timelines that the RTOs use to coordinate with other affected systems during the interconnection process. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
As of Jan. 1, the ISO’s interconnection queue contained about 43,000 MW of proposed generation, including about 28,000 MW of renewables, 12,000 MW of storage, and 2,800 MW of other resources, documents show.
Constitution Pipeline on Monday asked FERC to reconsider a January order upholding a denial of the company’s water permit application by New York environmental regulators, saying the commission “erred” in its interpretation of the federal Clean Water Act.
At issue is a proposed 124-mile natural gas pipeline originating in Pennsylvania that would deliver 650,000 dekatherms of gas per day into upstate New York.
First sections of Constitution Pipeline arrive in New York | Constitution Pipeline
Constitution last October petitioned the commission to rule that the New York State Department of Environmental Conservation (NYSDEC) had waived its authority under Section 401 of the Clean Water Act by failing to issue or deny a water quality certification within the one-year “reasonable period of time” stipulated by the act, despite the company’s cycle of withdrawing and resubmitting the application.
But the commission disagreed, ruling last month “that once an application is withdrawn, no matter how formulaic or perfunctory the process of withdrawal and resubmission is, the refiling of an application restarts the one-year waiver period under section 401(a)(1).”
Nonetheless, the commission said it continued to be concerned “that states and project sponsors that engage in repeated withdrawal and refiling of applications for water quality certifications are acting, in many cases, contrary to the public interest and to the spirit of the Clean Water Act by failing to provide reasonably expeditious state decisions.” (See FERC Upholds New York Denial of Constitution Pipeline.)
Constitution’s Feb. 12 petition calls on the commission “to curb this abuse of [the] legal process” in which DEC “has succeeded in delaying and frustrating the certification review process by claiming that Constitution’s serial submissions entitle the agency to successive year-long review periods.”
“The Commission erred in its interpretation of the “reasonable period of time” in this case because the mechanical application of the final submission date of April 27, 2015, wrongfully allowed NYSDEC to exceed the maximum allowable period of time under the Clean Water Act,” Constitution said.
The pipeline developer contends that the commission is fostering a regulatory scheme detrimental to the public interest and that its Jan. 11 order enables NYSDEC “to abdicate its responsibilities.” The company noted that, except for the Clean Water Act approvals, the project is federally approved and its right-of-way has been optioned or acquired.
“The piping and equipment for this project have now been held in storage for over three years, and the pipeline remains fully contracted with long-term commitments from established natural gas producers currently operating in Pennsylvania,” said the petition, which also requested expedited action by the commission to prevent further delay.
Constitution said its pipeline is a “critical natural gas infrastructure needed to meet the natural gas demands of the Northeast United States – the current winter supply and pricing environment in New England making this point most clear and obvious.” (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
In a proceeding related to the Millennium Pipeline, FERC last September ruled against the NYSDEC on a similar issue of timeliness, finding the agency had waived its authority to issue or deny a water quality certification for the project by failing to act within the one-year time frame required by the Clean Water Act (CP16-17). (See Environmentalists Denounce FERC Millennium Pipeline Ruling.)
VALLEY FORGE, Pa. — Stakeholders at last week’s Market Implementation Committee meeting denied four proposals to revise PJM’s rules on evaluating designated market paths for energy sales coming into and out of the RTO, indicating a preference for status quo.
Tim Horger of PJM and John Dadourian of Monitoring Analytics, the RTO’s Independent Market Monitor, presented proposals, along with Steve Kelly of Brookfield Renewable and Ruta Skucas from the Financial Marketers Coalition. The proposals differed on how strictly they would monitor scheduled transactions and the amount of leeway or consideration that companies would receive to demonstrate that questionable transactions were appropriate. (See “Stakeholders Battle PJM, Monitor on Market Path Alignment,” PJM MIC Briefs: Jan. 10, 2018.)
“Monitoring Analytics really thinks there needs to be an enforceable rule,” Dadourian said.
“We think the IMM and PJM are going a little too far. We don’t want to throw the baby out with the bathwater,” Kelly said. “We do agree with PJM and the IMM that intentionally breaking a transaction up into separate components to conceal the true source and sink should be defined as illegitimate activity and it should be repriced, so we’re definitely aligned on that matter.” However, Brookfield argued that companies should be allowed 10 days to prove their transactions are “legitimate” before they are resettled.
Skucas, representing a joint proposal from the FMC and American Electric Power, argued that there isn’t any data proving the existence of the issues the rule change is supposed to prevent. The proposal would exempt any transactions that are at least eight days long and would monitor activity at the company level rather than combining activity from all companies within a parent holding company.
AEP’s Dana Horton said that’s the reason his company signed on to the proposal.
“We have both regulated and unregulated subsidiaries in our corporation and we follow some strict policy guidelines on not communicating between the two, so the one side does not know trading positions on the other side, and this proposal from PJM would lump them together with no way of knowing we’re in violation until after the fact,” he said, adding that PJM’s plan wouldn’t offer a way to review and explain the issue.
Dayton Power and Light’s John Horstmann agreed.
“I think it’s a legitimate question. … You may put two and two together long before any entity within a single large corporation will [because of FERC’s code of conduct rules], and potentially punish them even though they didn’t even know the combination of transactions created a problem. I haven’t heard how we’re going to address that, other than we’re going to send you to FERC because you should have known better. It’s not that easy,” he said.
Horger presented an alternative proposal that would focus only on daily and hourly transactions and exempt large corporations like AEP that have legal separations between their affiliates.
Skucas and Monitor Joe Bowring agreed that the alternative proposal unnecessarily included a reference to possible referrals to FERC.
Carl Johnson, representing the PJM Public Power Coalition, also voiced concern about companies inadvertently breaking the rules.
“We’re setting up a set of circumstances where market participants really couldn’t know that they’re going to be tripping violations,” he said. “While we completely get why the sham scheduling should be addressed, we don’t want to support a set of rules that make it [that] you just get caught and you have no idea what you did.”
Bowring said companies would know exactly what activity they should avoid.
“There would be a list and you would know what the list is,” he said. “It’s up to individual companies to monitor their own trading activity, and if they can’t do that, it’s not a problem with the rules; it’s a problem with their monitoring.”
“Or it’s a problem with the way the rules are set up,” Johnson interjected.
Bowring said it was “odd” that companies’ inability to monitor their overall activity is being offered as a reason to not have a rule against manipulation.
“We still have concerns with this whole construct that we’re setting people up to fail and get resettled,” Johnson said.
All four proposals failed to reach the necessary voting threshold of 50% to be considered at the Markets and Reliability Committee. The FMC’s came closest with 44% in approval.
Stakeholders then discussed if there’s any benefit to continued discussion to work toward consensus, but Citigroup’s Barry Trayers said stakeholders appear to be at an “impasse.” Skucas said there needs to be data to support the issue, but Bowring said the activity has been suppressed in recent years because the regulatory risk associated with a joint statement from the IMM and PJM that made it clear that such activity was manipulative.
“The alleged data is not going to show that problem because it’s being suppressed,” he said.
“If the problem has been suppressed, then why are we doing this?” Skucas responded.
“Apparently we’re not,” Bowring said.
Stakeholders then voted 69% in favor of retaining the status quo, and PJM staff said they would recommend closing the issue.
FTR Focus
Several items at the MIC meeting focused on financial transmission rights. Exelon’s Sharon Midgley presented a problem statement and issue charge to address her company’s concern with what it found to be an 18-fold increase in FTR forfeitures since a FERC decision in January 2017 required rule changes that PJM implemented several months later. Monitoring Analytics’ Howard Haas said he has not seen evidence of the issues identified in the problem statement. The proposal will be up for endorsement at next month’s meeting.
| PJM
Direct Energy’s Marji Philips criticized PJM’s handling of remapping FTR paths when one of the nodes involved is eliminated. Philips said her company was presented with the issue several months ago and instead of finding an “electrically equivalent” substitute, PJM permitted them to terminate the FTR. She said other RTOs — specifically highlighting NYISO — find an equivalent.
“We think you ought to find an electrical equivalent, and coming back saying you can’t is not acceptable,” she said. “To some extent, I analogize this to a property right. We paid for it.”
Exelon, Vitol and DC Energymade the case for why long-term FTRs are beneficial to the market and should be retained. The presentation was in response to a proposal by the Monitor to review whether the products, which are available for each of the next three planning years or a combination of all three, are contributing to returning congestion revenue to load as intended.
Philips defended the Monitor’s proposal, saying that traders in her company profit off the product but also are concerned that “it may be wrong.” The products are far enough in the future that they’re “a joke from a modeling standpoint” and “not based on reality.”
“The reason that we continue to support the investigation is because … the right thing long term is to figure out whether these instruments are in any way impacting liquidity and revenue associated with [auction revenue right] and FTR allocations,” she said. “We participate because there’s a market out there and other people are participating in it and it’s not illegal and it’s perfectly sanctioned. But … we’re not sure that it’s right that we should be allowed to participate if at the end of the day we are impacting revenues that rightfully belong to customers or opportunities to get revenues that belong to the customers, and that’s our dilemma.”
PJM’s Chantal Hendrzak said the next step is to consider interests and design components.
VALLEY FORGE, Pa. — Stakeholders at last week’s Planning Committee meeting pushed PJM to expand its scope on several transmission-related issues, but staff resisted the effort in an attempt to keep a tight focus on specific rule revisions.
Stakeholders endorsed manual changes to revise PJM’s processes for new interconnection requests, but Ryan Dolan of American Municipal Power said the changes should go further.
The endorsed changes are part of a larger effort to replace an initial transmission study in the interconnection process with a more detailed feasibility study before moving to a costlier impact study. PJM’s Ed Franks said market participants won’t know the limiting elements on a line until a meeting later in the process, but Dolan argued they should be able to determine that information before submitting a project into the queue.
“I have no way of predetermining if a switch or another element [or] an entire line might be limiting me,” Dolan said.
“It’s relatively impossible to put that in the case. I think you can understand that,” PJM’s Aaron Berner said. “That’s a much broader topic.”
There were also concerns regarding PJM’s proposed Manual 14B changes because the RTO’s analysis found they would affect two flowgates, but Dolan argued the impact was potentially much greater and requested an analysis of the potential change to equipment.
“I fully understand the system is a dynamic system, but ultimately I think what we can only request be done right now is we at least take a snapshot of what we know currently of the system and how its topology is laid out, and we can make our decision based off of what is currently in our models,” he said.
Staff agreed to delay the endorsement vote for a month to provide that analysis.
Steve Huntoon, of Energy Counsel LLP, raised concerns about proposed changes to Manual 14A, which he called “overbroad and likely to result in a lot of confusion.”
“When I read the magnitude of this … there are some sweeping statements throughout here, and I’m very concerned about the implications of them,” he said.
Dolan also questioned the changes, voicing concerns about ratepayers being charged for more than their responsibility for necessary upgrades.
Berner again attempted to rein in the conversation.
“I think we’re straying from the manual here. The issues here are around how we process and handle our studies,” he said.
Berner suggested PJM provide participants additional education on the issue because some appear to be conflating withdrawal service and transmission service. Dolan said the education would be helpful because “now what I’m seeing here is they’re being grouped together here in one study process.”
“I just want to make sure that everybody at this committee is aware that non-firm transactions are contributing to overloads in the assessments,” Dolan said.
The Manual 14A revisions are planned to go for an endorsement vote at next month’s meeting.
PJM Proposes POI Solutions
Staff is proposing three options for resolving issues with points of interconnection (POI) for grouped generation projects, though none provides a perfect solution.
The first option would require a generation developer to sign on to the Tariff as a transmission owner for the line and a wires-to-wires POI where the gathering line connects to the grid.
John Brodbeck with EDP Renewables argued that FERC Order 807 creates ways for developers to avoid becoming TOs, but PJM’s David Egan disagreed.
“If you want the flexibility you’re asking for, you’re asking to have the TO construct,” Egan said. “The fact that you’re subdividing and doing whatever you want for your financing, really that’s your issue.”
Dayton Power and Light’s John Horstmann raised the concern that such requirements would change project calculations. For one thing, the developer would have five years to use up all the capability on a line it built or be required to open access to other developers.
“It’s a huge impact on the project,” Horstmann said.
The second option would require the local TO to assume control of the transmission infrastructure up to the connection point for the individual projects.
A third option would require the developer to combine all the projects into a single entity so it can sign a single interconnection service agreement.
“We currently have situations like this … and we typically have handled this as a shared facilities agreement,” Brodbeck said.
He asked if that was still an option or “if we’re becoming a TO, I assume … we get to vote as a TO, we get to walk around as a TO, and all these other things, right?”
Staff said they are working on splitting the manuals to pull out generator-specific revisions into a separate manual.
Capacity Factors
PJM is proposing several Manual 21 changes based on a review of data regarding generator performance.
Staff plan to shorten the summer generation testing period by one month, limiting it to July 1 through Aug. 31. They are also proposing to use the median capacity factor instead of the average capacity factor for both wind and solar resources, along with relying on the actual five-minute settlement values to estimate what output would have been absent curtailments of wind by PJM operations.
PJM data shows that the average and median capacity factors for solar performance in the summer are fairly similar. | PJM
PJM’s Jerry Bell reviewed staff research showing that average solar capacity factors are similar to median capacity factor results, but average wind capacity factors are quite different from median results. The study analyzed both summer and winter performance for both generation types.
The data analysis also found that five-minute settlement values for wind resources, which are available to the generators, are very similar to state estimator results, which they don’t have access to.
PJM data also shows that the average and median capacity factors for wind performance in the winter are not close enough to be interchangeable. | PJM
Finally, an analysis of testing data showed that generators tend to test during the best possible conditions, or test early and then retest if conditions improve.
“I’m not saying there’s any malicious intent here, but there may be things that we don’t see because we can’t get a view of the energy balance,” Bell said.
Roseland Conflict
PJM staff made it clear early during the discussion on the Roseland–Branchburg–Pleasant Valley Corridor that they intended to wrap up the months of discussion about the project.
“Our intent would be to not bring this back to the TEAC after this point,” Berner said.
However, AMP wanted to outline its concerns. Dolan brought up the results from a recent FERC decision that showed the cost to rebuild the line has nearly doubled.
PJM staff said past estimates were based on the amount of time it had to produce the numbers and were done using different methodologies. They defended the decision to install a double-circuit structure but only string a single circuit because the cost of expanding to a second circuit in the future would be “significantly” higher than the 10% adder included in the current estimate.
Staff also defended their rejection of simply not replacing the line based on the initial results of their analysis of that plan.
“What we see here is enough to conclude that’s a bad idea,” PJM’s Mark Sims said. “Just doing the first round of analysis gives us a severe enough of a result.”
VALLEY FORGE, Pa. — PJM staff told attendees at last week’s Operating Committee meeting that they are looking at ways to improve operations after reviewing the grid’s performance during January.
PJM’s Donnie Bielak and Joe Ciabattoni noted that the Tier 1 response to three spinning events during the cold snap that started the month before were substantially below the RTO’s estimates. At least 400 MW that were expected didn’t respond during each of the events, with as many as 1,660 MW failing to respond to a Jan. 7 event.
PJM has two tiers of reserves that are triggered sequentially when its dispatch software calculates a potential generation shortage. The Tier 2 response was much closer to the need. All estimated megawatts responded for two of the events.
Bielak said there are “preliminary discussions” internally regarding changes to address the issue and that “nothing is imminent,” but Calpine’s David “Scarp” Scarpignato called it “a pretty significant pricing issue” if anticipated reserves that never materialize are preventing scarcity pricing from triggering.
“I think this is going to need larger investigation by PJM and reporting out what you think the drivers of some of these numbers are,” he said.
Ciabattoni said staff did their normal outreach to the worst performers and found three main issues: poor communication from units’ market operation centers so they didn’t know to respond; “unrealistic” ramp rates attributable to equipment being out of service at the time; and spin max settings that were based on incorrect configurations.
“Our estimates are only as good as the data we get from our members,” he said. “When we did the outreach, we did find that there were data-quality issues.”
“These are bad estimates at the most critical time for scarcity pricing. Scarcity pricing is supposed to kick in during these conservative ops,” Scarp said.
Generators are addressing their issues, Ciabattoni said, and PJM is considering rule revisions to allow for raising the output target dispatchers send to units, known as the base point.
“PJM doesn’t change our base point when we go into a spinning event, so there’s not a direct signal to tell the unit to load,” Ciabattoni said.
Direct Energy’s Marji Philips asked why there were about 100 more planned outages than any other month in the past year.
“Both forced outage rates and total outage rates were elevated, and that’s primarily due to the cold weather we experienced in the first week of January,” Ciabattoni said.
He explained that if an operator needed to take an unplanned, or forced, outage but can wait until “a more opportune time, then we grant you what’s called a maintenance outage,” which is categorized as a planned outage.
The RTO’s off-peak load forecasting error of 2.79% in January was the highest in more than a year. The on-peak error was 2.38%, both of which were increased by the cold weather, Ciabattoni said. Their combined average of 2.58% was still well within PJM’s 3% monthly target threshold. The largest outlier was 7,000 MW on Jan. 15, which was the Martin Luther King Jr. Day holiday, he said.
In the 10 years that PJM has been measuring its “perfect dispatch” metric, there have only been two months in which the metric has estimated $0 production cost savings: January 2014 during the so-called “Polar Vortex” and January 2018 during the recent cold snap. | PJM
“Our model treats that as a holiday. In the past, that’s worked very well for us. This year, the load actually came in more like a normal workweek.”
The RTO also estimated no production cost savings from its “perfect dispatch” initiative for the first time since the cold streak during January 2014 known as the “polar vortex” and the second time ever in the 10 years PJM has been tracking the metric. Over those 10 years, PJM estimates its efforts to accurately forecast demand and dispatch generation as economically as possible has saved more than $1.4 billion in production costs.
PJM’s Ken Seiler said the RTO is compiling a report on grid performance during the winter that will be available by the end of this week.
Task Force on Mandating Primary Frequency Response Nearing Solution
PJM’s Glen Boyle announced that stakeholders have presented five proposals to address FERC’s requirement that most generation units be able to provide primary frequency response. The proposals are focused on four components: an exception process, an implementation plan, how performance will be measured and how units will be compensated. Stakeholders have differed on whether the service is already included in the compensation units receive in auction commitments or should receive separate compensation. (See PJM IMM Opposes Frequency Response Payment Bid.)
Stakeholders will vote on the packages after the task force’s next meeting on Feb. 28 and any that receive 50% endorsement will move on for consideration at the Markets and Reliability Committee. Boyle said few stakeholders have expressed much interest, so wider participation would be “appreciated.”
Lack of Adjustment Requests a Surprise
PJM’s Alpa Jani reminded stakeholders that the deadline for unit-specific parameter adjustment requests is Feb. 28 and expressed surprise at the lack of requests so far. She said the RTO expected many more requests from new base and Capacity Performance resources this year that haven’t materialized.
The process allows CP, base or replacement resources to submit adjustments to their commitments based on an actual operating constraint. Any newly approved adjustments will go into effect on June 1, while any existing ones will roll over from previous years.
Super Bowl Impact
Seiler was able to compile some analysis from energy demand during Super Bowl LII on Feb. 4. There was a 750-MW increase in load just prior to the start of the game, he said, and another 700-MW bump at halftime.
“There must have been a commercial that was kind of boring, so we saw another 200-MW jump about 30 minutes later,” he said, and then another 500-MW spike after the game.
Operators could tell the game was good because the load tails off quickly during bad games and the spikes don’t occur throughout the game, he said.
Black Start RFP
Staff held a special session of the OC after the meeting to walk through its request for proposals for black start service. The RTO initiates a black start RFP process every five years. The current request was issued on Feb. 1 for projects expected to be operational around May 2020.
PJM has developed a two-tiered approach for proposals to balance the resources proposed by bidders with staff’s need to see what is available across the RTO’s footprint without specifying where black start is needed. Initial proposals with basic information must be submitted by March 8. PJM would then decide whether to pursue that proposal, and those bidders would have until May 31 to submit a full, detailed proposal.
Units would receive revenue based on their actual costs to develop the project, plus a 10% profit margin.
