ST. PAUL, Minn. — MISO’s external affairs operation wants to reboot its website and is seeking a separate $1 million budget to begin research and development.
The RTO’s project is aimed at freshening its online presence for the public and its membership, and increasing the use of website-usage analytics.
The external affairs division handles MISO’s online communications, meetings, and member and stakeholder relations. Its current $11 million budget is expected to become a $13 million budget over the next five years while membership grows.
Vice President of MISO South Todd Hillman told the Board of Directors’ Corporate Governance and Strategic Planning Committee that the RTO may be lagging behind customers’ technology expectations, as it has performed only two website redesigns in 12 years. It still uses a call center — each of the 430 market participants are assigned customer representatives — to handle issues that Hillman said could be better addressed online or with an app.
“We’ve focused on the touch of our customers, but not the tech of our customers,” Hillman said.
Hillman said MISO has just “scratched the surface” of data analytics. He asked the board to approve a $1 million budget for next year to hire a third party to conduct a comprehensive analysis on a possible new online interface and social media presence that can be adjusted using data analytics.
Directors asked if $1 million was enough to develop improvements. Hillman said if MISO was “diligent,” the amount could work. He said consultants could bid against each other for the best prices.
Director Paul Bonavia also said he hoped MISO would get “a little crazy” with the scope and not restrict it unnecessarily.
Hillman said there is no reason MISO should be limited in its web presence. It could look to other companies who communicate online across multiple channels. “We need to stop looking to other RTOs’ [websites]; maybe we look at Amazon for some ideas,” suggested Hillman, who said a MISO membership app could become a reality.
Hillman said MISO relies heavily on an annual customer service survey for feedback, which Bonavia called “a blunt instrument.” CEO John Bear agreed that more periodic feedback would be helpful.
SARATOGA SPRINGS, N.Y. — Gavin Donohue, CEO of the Independent Power Producers of New York, opened the group’s fall meeting last week by declaring as its top priority NYISO’s reset of the installed capacity demand curve.
Donohue noted the ISO’s prediction that New York’s Clean Energy Standard will significantly increase the need for reserve capacity and highly dispatchable resources.
“Combined with the uptick in announced plant retirements, it has never been more critical to get the demand curve reset right,” Donohue said. “The demand curve is responsible for setting reference prices. It will determine what resources enter the market over the next four years.”
The reset, which has been conducted every three years, is moving to a four-year cycle (with annual updates of some parameters). The ISO staff released its final recommendations Sept. 15 on the new parameters, which include net energy and ancillary services revenues and the gross cost of new entry in addition to reference point prices.
Staff adopted the recommendations of its consultant, The Analysis Group, for reference points for all but the New York Control Area. The firm recommended the reference points for all regions be based on dual-fuel requirements, while staff said the NYCA — the rest of state, excluding Long Island, New York City and the Lower Hudson Valley — should be based on gas only. Staff also shaved the proposed price for NYCA by 4.5%, rejecting the consultant’s proposal of $11.22/kW-month in favor of $10.72/kW-month.
Donohue also noted generators struggled with low load growth and record low gas prices, which he said are “driving previously economic facilities to the brink and resulting in various forms of state intervention.”
“It’s not clear how this effort will play out. But it’s clear that market-based solutions are always preferable to out-of-market solutions in New York state,” he said.
The ISO will accept written comments on the proposed demand curve through Oct. 3, with oral presentations to the Board of Directors on Oct. 17. The board’s finalized parameters will be filed for FERC approval by Nov. 30 with the revised curves taking effect May 1, 2017.
ST. PAUL, Minn. — MISO Steering Committee members are asking if there is a need to formalize the creation and retirement of task teams following the Resource Adequacy Subcommittee’s contentious decision in July to retire the Competitive Retail Solution Task Team.
“There’s no formal process for retiring a task team, and there’s good reason for that. Task teams do not follow the Stakeholder Governance Guide,” Steering Committee Chair Tia Elliott said. “I heard from stakeholders that it’s important to keep that process outside of formalization.”
American Electric Power’s Kent Feliks said he opposed formalizing task team creation and that, like PJM, MISO could use special meetings to discuss issues that would cut down on the number of task teams that parent entities create.
Resource Adequacy Subcommittee Chair Gary Mathis said it may be helpful to insert language into the Stakeholder Governance Guide to define how task teams are formed and dissolved.
Ameren’s Ray McCausland said Robert’s Rules of Order currently govern the creation and disbanding of task teams, because the Stakeholder Governance Guide defers to Robert’s Rules when directions “aren’t otherwise stated.”
Mathis said the bylaws are worded so that only parent entities are required to follow Robert’s Rules, not task teams. Feliks said he preferred leaving the creation and dissolution of task teams up to parent entity leadership.
After discussion, the issue was tabled until the Steering Committee’s Nov. 3 Stakeholder Governance Guide workshop.
Steering Committee members also discussed whether changes are needed to get callers queued up more quickly during meetings. Currently, entity chairs are in charge of recognizing callers with opinions and questions.
Currently, McCausland said, operator-assisted calls are in violation of the governance guide. He said callers should be able to interrupt the speaker directly by deselecting their mute buttons. He argued that people attending in-person have rights that those dialing in do not have.
“It’s a brainer. We have to think about this,” Mathis added.
Elliott said the issue could be handled by MISO with a technology fix, possibly through a function that allows callers to immediately open lines without operator assistance.
FERC last week approved Macquarie Energy’s request to revise its market-based rate tariff to allow the company to engage in short-term simultaneous transactions along a key Pacific Northwest transmission system partly controlled by Puget Sound Energy — a Macquarie affiliate (ER16-2198).
The commission’s decision enables Macquarie to trade energy and capacity with an unaffiliated counterparty on the California Oregon Intertie (COI) north of the California Oregon Border (COB) trading hub while at the same time executing an opposite transaction at the John Day hub in central Oregon.
COB is a major delivery point for wheeling Northwest generation intended for markets in California. The John Day hub is predominantly used to price bilateral transactions involving output from hydroelectric and wind resources in central and eastern Oregon and Washington, often intended for delivery into California.
The John Day Dam and its substations comprise a primary pricing point for bilateral transactions involving output from hydroelectric and wind resources in central and eastern Oregon and Washington — often intended for delivery into California. Photo source: Oregon Dept. of Energy
PSE is one of six holders of capacity on the northern portion of the COI, with Seattle City Light, Pacific Northwest Generating Cooperative, Snohomish County Public Utility District, Tacoma Power and PacifiCorp’s merchant arm making up the rest of the group. The COI’s owners — Bonneville Power Administration, PacifiCorp and Portland General Electric — also control capacity on the system, which consists of three parallel transmission lines.
Macquarie Energy and PSE are both subsidiaries of Australia-based investment bank Macquarie Group.
Headquartered in Houston, Macquarie Energy operates as an independent power marketer throughout the U.S. The company does not own or operate generation or transmission assets in the Northwest, controlling only a small amount of generation, in the PJM balancing authority area, through long-term contracts. PSE is a vertically integrated utility serving about 1.1 million electricity customers in northern Washington. The utility also operates a wholesale marketing arm.
In 2012, the commission ruled that “when a simultaneous exchange transaction involves the marketing function of a public utility transmission provider, the public utility must seek prior approval from the commission if the transaction involves its affiliated transmission provider’s system.” Approval of such transactions would be made on a case-by-case basis, the commission said.
Macquarie’s July 14 FERC filing requesting the tariff change contested the need for the company to obtain prior authorization to engage in transactions at COB and John Day. The company said that while it is technically an affiliate of PSE, it does not function as PSE’s wholesale marketer or buyer.
The commission rejected that contention.
“We are not persuaded by Macquarie Energy’s argument that, because Macquarie Energy neither markets any of Puget Sound’s generation nor purchases any power for or on behalf of Puget Sound and only purchases point-to-point transmission from Puget Sound, its affiliate relationship with Puget Sound is not equivalent to acting as the wholesale merchant function of a transmission provider and therefore merits different treatment,” the commission wrote, adding Macquarie could potentially perform PSE’s wholesale market function.
The commission nonetheless authorized Macquarie to engage in the proposed trades, saying the company provided FERC with sufficient information to evaluate the transactions.
“We find that Macquarie Energy has adequately addressed the commission’s concern regarding circumvention of open access requirements and has demonstrated that its proposed transactions are not an attempt to offer transmission service without reserving transmission,” the commission wrote.
More important to the commission was the fact that Macquarie cannot use PSE’s network transmission to engage in the transactions, but must instead purchase point-to-point service in order to move energy between COB and John Day.
“The inability to use network transmission service mitigates the concern that Macquarie Energy’s proposed transaction will allow Puget Sound to earn revenue from both the explicit sale of transmission service and the implicit sale of transmission service via Macquarie Energy’s proposed transactions,” the commission wrote.
Furthermore, given the diverse ownership of capacity on the COI, Macquarie is not limited to purchasing point-to-point service from just PSE.
“Moreover, any transmission service obtained by Macquarie Energy on the COI would be under the [tariff] of the entity providing the service, including Puget Sound,” the commission said.
AARP and the Public Utility Law Project want New York regulators to provide more documentation to justify the Clean Energy Standard’s estimated $2/month rate increase for the average consumer.
The groups wrote to the New York Public Service Commission last week, saying the commission’s Aug. 1 CES order did not explain the costs to keep upstate nuclear power plants operating with zero-emission credits. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
“AARP and PULP are very concerned that the Clean Energy Standard implementation (particularly the subsidy for power plants) may have costly impacts on New Yorkers already facing among the highest electricity rates in the nation,” the letter states. “The mention of a potential $2/month residential bill impact from the Tier 3 purchase of zero-emission credits in the order was not accompanied by any details or citation to where such an estimate was derived and fails to provide sufficient cost and bill impact information for each customer class, for each utility, or for the entire 12-year commitment to support these power plants.”
The groups cite estimates by PSC staff that the ZEC program could cost up to $8 billion over its 12-year term.
They also cite other utility programs that will be borne by ratepayers, including a $1.5 billion smart meter program in the Consolidated Edison territory, cost recovery for distributed energy demonstrations projects and $5 billion for clean energy and energy efficiency programs run by the New York State Energy Research and Development Authority.
These cases and the CES “simply cannot be viewed separately,” the groups add.
The letter comes days after downstate legislators complained that the ZEC program costs were disproportionately burdensome on New York City-area ratepayers. The PSC pushed back in a reply, saying the economic benefits and reduced emissions benefited ratepayers statewide. (See New York Legislators Question Nuclear Subsidy.)
VALLEY FORGE, Pa. — PJM’s Planning Committee held a special session last week to begin soliciting stakeholder input on changes to the RTO’s selection process for Order 1000 projects.
The goal of the ongoing sessions is to develop consensus on how decisions are made prior to the opening of the Regional Transmission Expansion Plan’s long-term proposal window Nov. 1, said Steve Herling, PJM’s vice president of planning and chair of the committee. The window, for market efficiency projects, will remain open through March 2017.
Eventually, the rules will be incorporated into PJM’s governing documents and receive FERC approval, but Herling acknowledged “there’s no way in the world that we’re going to have this approved at FERC before Nov. 1.”
At the meeting, PJM staff explained their concepts for the process, outlined a workflow diagram and highlighted a variety of examples to help stakeholders understand how PJM is likely to evaluate proposals.
“We’re trying to lay out our past thinking on this,” Herling said, “but … one of the whole points of this exercise is to start collecting metrics that you think need to be” included.
PJM hopes the input will provide perspectives it hadn’t considered so that proposals receive accurate, fair comparisons. While staff is attempting to be holistic in its evaluations, “we can’t say with absolute certainty that there won’t be a question raised by one of you that [shows] we missed some key benefit of one of your projects,” Herling said.
The RTO’s first Order 1000 project, the stability fix for Artificial Island in New Jersey, has been the subject of years of controversy and delay, both over PJM’s developer selection process and the resulting cost allocation. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
For market efficiency projects, PJM factors net load payment benefits, production cost benefits and overall PJM congestion benefits into its evaluation and requires a benefit-to-cost ratio greater than 1.25 to pass. Proposals that pass the B/C test then get evaluated for congestion reductions and overall changes, load payments, production costs and associated sensitivities, such as gas and renewable penetration, carbon policy and import/export requirements.
Stakeholders asked that development cost be considered and requested as much quantitative guidance as possible. They voiced concern about how carbon dioxide assumptions, forecasted long-term benefits and proposals offering cost caps are factored into the evaluation.
“We can’t have economic thinking thrown out the window here once a project crosses the B/C ratio,” Sharon Segner of LS Power said. PJM’s Suzanne Glatz pointed out that projects estimated to cost more than $50 million require independent cost analyses and constructability analyses.
“We do reserve the right to kind of break [proposals] down and put them back together to create a better, more cost-effective solution,” Herling said.
Further meetings on this topic are scheduled for Oct. 3, Oct. 21 and Nov. 11, during which PJM staff will introduce the regional metric for project selections.
SARATOGA SPRINGS, N.Y. — A forward capacity market may have worked for PJM and ISO-NE, but it isn’t the solution for NYISO, the Market Monitor told the Independent Power Producers of New York’s fall conference last week.
PJM and ISO-NE officials told an audience of about 100 that their forward markets have successfully incented new generation to replace retirements in their regions.
But The Analysis Group’s Paul Hibbard said the consulting firm’s 2015 study for the ISO found no compelling benefit to changing from New York’s current monthly prompt auctions. “We couldn’t find in our analysis … a real overwhelming level of support or level of rationale for … going through the effort of moving to a forward capacity market design,” said Hibbard, who moderated the session.
And Pallas LeeVanSchaick of Potomac Economics said instituting a forward market would be a time-consuming distraction from addressing the ISO’s biggest problems.
The Monitor called for “more logical local capacity requirements” and predefined capacity zones “so that resources know that if they come into a particular area to meet a reliability need … that there’s an economic signal that they’ll be rewarded for helping to satisfy.”
“Those would be important whether you have a spot market for capacity or a forward capacity market,” he added.
Robert Ethier, vice president of market operations for ISO-NE, said his RTO was forced to accept the forward capacity model in FERC-moderated settlement talks. “We were actually focused on a monthly market with a sloped demand curve much like you have here in New York,” he recalled.
Despite its origins, and the repeated changes to market rules since then, Ethier said, “it’s working pretty well.” The RTO says it has attracted 4,700 MW of new capacity resources — versus 4,200 MW of retirements — since 2013.
“That’s sort of the bottom line … for a capacity market: Is it getting you new resources to replace the resources that are exiting the market?” he continued. “At that high level, it’s been successful.”
Among the changes ISO-NE made was adjusting the calendar to address a disconnect in the auction timeline.
Retirements had been allowed up to one month before auction, while new resources had to declare their intent to enter the market a year in advance. Because it was impossible for new resources to respond to late-announced retirements, the RTO found itself with capacity shortfalls in Forward Capacity Auctions 8 and 9.
In April, FERC approved rules requiring retiring generators to declare their intention in March rather than October, while moving the “show of interest” deadline for new capacity market entrants from February to April. (See FERC Approves Changes to ISO-NE Retirement Rules.)
‘Not Here to Sell Anything’
Also on last week’s panel was Stu Bresler, PJM’s senior vice president of operations and markets, who responded to LeeVanSchaick’s criticism by making it clear “I’m not here to sell anything” to NYISO. He also acknowledged that PJM’s Reliability Pricing Model is “not immune” to changes, an apparent reference to a call by some stakeholders for an overhaul. (See Proposal to Revisit PJM Capacity Model Receives Tepid Response.)
But he noted that PJM has added almost 17,000 MW of capacity resources in the last five Base Residual Auctions, well in excess of the less than 2,500 MW of retirements announced. “If we didn’t have the forward capacity market, we’d have needed something else” to attract the new supply, he said.
The new resources mean that PJM, unlike NYISO and MISO, has rarely had to rely on reliability-must-run units. “If you define your region and your locational requirements for capacity sufficiently, you may have [only] some extremely localized issues that … will require some minor out-of-market actions.”
Ethier said ISO-NE has never had to invoke “backstop intervention” for reliability and has limited authority to do so. The capacity market, he said, is what ensures reliability.
“It focuses the mind and sharpens the pencil when you’re playing without a net,” he said.
Different Era, Different Needs
LeeVanSchaick said, however, that the concerns that prompted the capacity markers in the neighboring RTOs don’t apply to New York today.
Unlike the rapid load growth eras in which PJM and ISO-NE developed their capacity markets, New York is facing very little load growth, and new renewable resources are entering the market, driven by public subsidies, he said.
LeeVanSchaick also said the one-year commitment with a three-year forward time horizon is a bad fit for existing resources considering making capital investments they expect to pay back in five to 10 years. “And … the time frame in which they would make that decision is not three years ahead; it might be more like one year ahead,” he added. Forward markets don’t “line up well with those investment decisions, certainly not with the time frame in which demand response providers are looking to increase or decrease their position in the market.”
He said the ISO also needs to increase its reliance on the energy and ancillary services markets to recognize the value of more flexible resources needed to supplement intermittent generators.
And he called for tougher rules on buyer-side mitigation and combatting uneconomic retention.
Cost, Time
The Analysis Group’s Hibbard said his firm’s report estimated it would cost $10 million and take three years to create a forward capacity market.
Both Ethier and Bresler said the additional administrative costs of the forward auctions are insignificant given the size of their $3 billion and $7 billion-plus markets, respectively.
Ethier estimated the forward market increased ISO-NE’s administrative costs by about $1 million annually compared to a prompt market. Bresler said seven PJM employees administer the RPM.
But Ethier acknowledged LeeVanSchaick’s concern about the “opportunity cost” of implementing the market.
“It basically slid all our initiatives out a couple of years. We would have had hourly markets much sooner, for example.”
LeeVanSchaick said the rationing of resources to pursue market initiatives suggests “the ISO budgets are lower than maybe the efficient level of funding for an ISO. … There’s often haggling over a small amount of money to develop a new project [even though] any of the projects that we’re talking about could potentially pay for themselves from the social welfare standpoint in a matter of months.”
SPP last week released tentative billing statements for transmission upgrades for 2008 to 2016, while its Z2 Task Force developed six options for addressing Group B and Group C waiver requests.
SPP’s most recent calculations show Group B members (transmission customers that SPP said didn’t qualify for waivers from paying their Z2 bills) have $36.9 million in directly assigned upgrade costs. Directly assigned costs for Group C (members who didn’t request waivers) total $77 million. The costs of Group A members, whose waiver requests were supported by SPP staff, totaled about $56.4 million.
The options for Groups B and C include:
Rejecting all waiver requests, as staff recommended to the Board of Directors in July. The board did not adopt the recommendation at the time.
Accepting all waivers as a one-time request to address catch-up concerns. Costs would be recovered through the Tariff’s regional/zonal cost allocation.
Regionally uplifting $44 million in directly assigned upgrade costs on Oklahoma Gas & Electric’s Windspeed II, a 126-mile, $218 million project, following a suggestion from Sunflower Electric Power, which said the project affects more transmission requests than any other.
Regionally uplifting the entire cost of the Windspeed project.
Applying previously approved “roll-in” criteria for assigning certain transmission facilities’ costs to the region.
American Electric Power resurrected its proposal from July’s MOPC meeting as a sixth option. AEP’s suggestion, which was rejected by the MOPC, would waive all of both group’s directly assigned costs and recover them through SPP’s base plan funding mechanism. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)
At the members’ request, staff will study the financial impacts of each option by zone and customer, and supply the numbers before the task force’s Sept. 30 meeting.
The group approved a motion to consider both Groups B and C for waivers, though the Group C members never requested waivers. “Just because a group didn’t ask for waivers, they shouldn’t be treated any differently,” reasoned Southwestern Public Service’s Bill Grant.
Z2 Summary Reports
As promised, SPP released draft summary reports on the Z2 revenue credits and charges incurred from 2008 to 2016. The information was made available to market participants through the RTO’s member section of the Marketplace Portal.
SPP said it is providing this information so transmission customers can validate their revenue credits and charges and determine whether to opt for a payment plan.
The information reflects the results of a second run of historical data processing, covering the March 2008-June 2016 period. SPP said it plans to do a third run before issuing final Z2 settlement invoices in November. It warned customers they will see “small” differences between the summary reports and the November invoices.
The summary reports, based on initial settlement calculations, depict all financial amounts as positive amounts; receivable amounts are typically shown as negative amounts in SPP’s normal transmission statements and invoices.
Companies registered as both transmission owners and transmission customers or generator-interconnection customers received one owner report and a second customer report.
SPP also posted additional data used to make the initial settlement calculations to a password-protected GlobalScape folder. Customers will have to complete a nondisclosure agreement to access the data.
PJM must develop a new method for allocating auction revenue rights that doesn’t consider extinct generators, FERC ruled last week.
The commission said PJM had correctly diagnosed that its existing rules for ARRs and financial transmission rights were no longer just and reasonable because modeling assumptions it adopted to address FTR revenue inadequacy had “resulted in unwarranted cost shifts between ARR holders and FTR holders” (EL16-6-001, ER16-121).
But it rejected PJM’s proposal to address the problem by reducing Stage 1A infeasible ARRs by increasing its zonal load forecast growth rate. FERC said the proposed escalation factor “would trigger unnecessary transmission enhancements” because it would rely on outdated historical source and sink points.
“Instead, to address infeasible Stage 1A ARRs, we require PJM to revise its Tariff to remove the use of historical generation resources for requested ARRs in Stage 1A of the allocation process if those resources are no longer in service and develop a just and reasonable method of allocating Stage 1A ARRs based on source points that reflect actual system usage.”
FERC also shot down PJM’s proposal to eliminate the netting of negatively valued FTRs against positively valued ones in holders’ portfolios, saying the RTO had not proven that the netting rules were unjust and unreasonable.
In addition, the commission agreed with PJM that underfunding can be reduced by excluding imbalance costs not related to day-ahead congestion from FTR settlements. It ordered that PJM allocate balancing congestion to real-time load instead.
PJM has 60 days to submit a compliance filing reflecting the Tariff changes directed by FERC.
The commission called for the information-gathering session after the Financial Marketers Coalition and others protested PJM’s proposal to eliminate the netting provision, which would have increased ARR results by 1.5% annually.
The coalition — representing DC Energy, Inertia Power, Saracen Energy East and Vitol — objected to the elimination of netting, saying PJM hadn’t proved that the rules were unjust and unreasonable, nor that the proposed changes would fix underfunding.
An FTR entitles its holder to credits based on locational price differences in the day-ahead energy market when the transmission grid is congested. FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.
‘Sidestep’
FERC noted that PJM described its proposed escalation factor “as a targeted reform intended to sidestep the underlying allocation dispute (and corresponding stakeholder impasse).”
Since March 2011, the RTO has held three separate stakeholder processes to address FTR revenue adequacy.
Stakeholders and PJM had been wrangling with the issue of FTR underfunding for more than a year when Steve Lieberman of Old Dominion Electric Cooperative offered a proposal combining recommendations from the RTO and the Independent Market Monitor.
Although the proposal fell short of reaching the consensus necessary to make a filing under Section 205 of the Federal Power Act, PJM offered it as a unilateral filing under Section 206. (See PJM to File FTR, ARR Rule Changes with FERC.)
FERC said that short-term changes implemented by PJM because of the lack of stakeholder consensus on a comprehensive fix had improved revenue adequacy “to better than historical levels” but unfairly shifted revenues from ARR holders to FTR holders.
“When it is required to issue a pro rata reduction in transmission congestion credits due to underfunding, its netting policy … results in a cost shift from participants with larger shares of positive target allocation FTRs to participants with larger shares of negative target allocation FTRs,” reducing the hedging value of prevailing-flow FTRs, the commission said.
Because PJM’s current Tariff requires it to use historical paths in its Stage 1A ARR allocation, the RTO has modeled “dummy generators” where the historic source points are no longer in service, creating a disconnect between the Stage 1A ARR allocation and actual system usage.
That can result in infeasible Stage1A ARRs, “as some pathways may appear to be infeasible even though, in actual system usage, these lines are not overloaded. As the PJM Tariff has no mechanism by which to update this requirement, future changes in the resource mix and retirements will only further exacerbate this issue,” FERC said.
The commission clarified that Order 681, its 2006 rulemaking on long-term firm transmission rights, “does not guarantee, or require PJM to use, historical paths” in its ARR allocation.
Doesn’t Address Root Cause
FERC said PJM’s proposal to increase zonal load growth “is an inappropriate solution that does not address the underlying root cause” of infeasible ARRs.
It said the proposal “could trigger transmission enhancements to paths that are not needed for reliability and are not able to be justified through the benefits of relieving congestion through PJM’s economic planning process.”
“Any transmission enhancement identified under escalated load projections distorts the planning process, such that transmission planning is not based on expected system conditions. Additionally, in some cases, these paths may reflect generators that no longer exist or generation that load no longer utilizes (due to sale of the generation unit or the termination of a bilateral contract). PJM’s existing [Regional Transmission Expansion Plan] process would not identify a need to build the transmission enhancements for projected reliability or market efficiency needs without using an adjustment unrelated to system needs. Moreover, developing transmission enhancements solely to address infeasible ARRs ignores the more fundamental issue of why PJM should continue to model requested ARRs based on historic generation paths that load no longer utilizes.”
Netting Proposal
PJM said its plan to eliminate netting was justified because participants with fewer negative target allocations subsidize those with more negative allocations.
But the commission said it was “not persuaded that counterflow FTRs actually contribute to FTR revenue inadequacy or that the elimination of netting would improve FTR funding.”
It agreed with arguments by the Financial Marketers Coalition that portfolio netting does not result in cross-subsidies among parties holding prevailing flow and counterflow FTRs because the current practice guarantees that both positive and negative target allocations are treated in the same manner.
“We further find that PJM’s proposal would only reallocate FTR revenue inadequacy among various market participants without actually addressing the fundamental issues associated with FTR revenue inadequacy.”
FERC disagreed with the Market Monitor’s assertion that a market participant can protect itself from FTR revenue inadequacy by holding counterflow FTRs to shrink its net positive target allocation.
“The Market Monitor’s argument is flawed because it ignores the fact that market participants take into account expectations of FTR revenue inadequacy when transacting in FTR auctions, a point that the Market Monitor even noted in its 2015 Quarterly State of the Market Report,” the commission said.
It also disagreed with Exelon’s contention that holders of counterflow FTRs are not exposed to underfunding under the current netting rules.
“PJM and commenters supporting the elimination of portfolio netting have not provided evidence sufficient to reverse established commission precedent that states that PJM’s existing netting provision is just and reasonable,” FERC said.
Balancing Congestion
The commission acknowledged that its ruling that PJM change its handling of congestion imbalance — caused when there is less transmission in the real-time energy market than was assumed in the day-ahead market — represented a shift from its 2013 FirstEnergy Solutions order, in which it ruled that challengers had failed to prove the methodology was unjust and unreasonable (EL13-47).
“Such a finding does not preclude the commission from re-examining the issue when circumstances have changed or additional evidence has been presented,” it said. “By the time of the PJM filing in this case under Section 206, circumstances had changed considerably.”
The commission said including balancing congestion in the settlement of FTRs “contributes to the identified unjust and unreasonable cost shift between ARR holders and FTR holders, is inconsistent with cost causation principles and reduces the efficacy of FTRs as a hedge.”
Back to the Stakeholder Process
Following the technical conference, the commission solicited comments on other issues, including updates to the seasonal feasibility tests and source and sink points and whether transmission owners were incented to schedule outages in alignment with FTR/ARR rules.
But the commission said it would not order additional changes on those points. “While additional improvements to PJM’s ARR/FTR construct may be warranted, including those proposed by commenters, we refer these proposals to the PJM stakeholder process for further consideration and development.”
U.S. Interior Secretary Sally Jewell on Wednesday approved the first phase of the Desert Renewable Energy Conservation Plan (DRECP), a framework for California’s development of renewable energy projects on 10.8 million acres managed by the Bureau of Land Management.
Jewell’s approval of the bureau’s land use plan amendment marks the conclusion of Phase 1 of the DRECP, which identifies priority areas for developing renewable resources on federal lands within California while setting aside acreage for conservation and recreational uses.
Phase 1 is the product of a collaboration among the California Energy Commission (CEC), the California Department of Fish and Wildlife, the U.S. Fish and Wildlife Service and BLM.
“This landscape-level plan will support streamlined renewable energy development in the right places while protecting sensitive ecosystems, preserving important cultural heritage and supporting outdoor recreation opportunities,” Jewell said.
The bureau’s land use plan “designates development focus areas with high-quality solar, wind and geothermal energy potential and access to transmission, sited in low-conflict areas,” the Interior Department said in a statement. Developers in those areas will benefit from “a streamlined permitting process, predictable survey requirements and simplified mitigation measures.”
Source: Tom Brewster Photography via U.S. Bureau of Land Management
The DRECP’s first phase is part of a broader California effort to open up a total of 22 million acres of public and private desert lands for renewable energy projects, an effort that could yield an additional 27 GW of additional renewable capacity, according to the CEC.
Phase II of the plan focuses on aligning local, state and federal renewable energy development and conservation plans, and building on CEC grants already awarded to California counties to foster renewable development.
Use of desert lands is a vital component in California’s strategy to meet its greenhouse gas reduction goals and derive 50% of its electricity from renewable resources by 2030. Development in those areas will become especially important if the state’s load-serving entities cannot obtain sufficient output from out-of-state resources. (See California Policy Goals to Require Significant Transmission Upgrades.)
“Renewable energy is a key part of California’s approach to addressing climate change, and large-scale renewable energy projects in the California desert will play an essential role in California meeting climate and renewable energy goals,” CEC Commissioner Karen Douglas said. “The DRECP provides a clear pathway for projects on public lands while giving the state much greater certainty about where those projects could be located.”
The announcement was met with opposition from renewable energy groups, which say the DRECP fails to balance renewable growth with land preservation and “forecloses development” on millions of acres of federal lands in Southern California. The plan sets aside 388,000 acres for renewable development, much of which is not suitable for solar and wind projects, the groups say.
“No one is saying that utility-scale renewable energy should go everywhere, but done responsibly and with safeguards, it does have to go somewhere if we are to meet state, national and global carbon-reduction goals,” said Nancy Rader, executive director of CalWEA, which estimates the plan will create the potential for 1,000 MW of new wind resources.
“The Interior Department and BLM missed a golden opportunity to balance the preservation of parts of the California desert with clean, renewable energy development across some of America’s richest renewable resource areas,” said Tom Kimbis, acting president of the Solar Energy Industries Association.
Shannon Eddy, executive director of the Large-scale Solar Association, called the plan “a Model T in a Tesla world,” arguing that it fails to consider the “enormous” policy changes that will require renewable development on public land.
“Rather than fostering sustainable clean energy development as a part of a conservation plan, it severely restricts wind and solar,” Eddy said.
Environmentalists praised the plan, which sets aside nearly 2.9 million acres as new federal conservation land.
“This plan is a win for California,” said Doug Wheeler, former California secretary for natural resources. “Not only does it help the state meet renewable energy goals, it also protects some of California’s best places — lands that provide a recreational escape and protect important wildlife species.”
“The DRECP provides a responsible path for future development while permanently protecting the most important places as California desert conservation lands,” said Danielle Murray, senior director at the Conservation Lands Foundation. “We thank Secretary Sally Jewell and the Bureau of Land Management for this landmark plan and hope it serves as a model for public lands planning in the future.”
