Citing FERC’s concerns over supplemental transmission projects, Kentucky regulators have rejected upgrades to two substations, ruling that Kentucky Power failed to prove they were needed.
The Kentucky Public Service Commission released an order on March 16 granting a certificate of public convenience and necessity (CPCN) to Kentucky Power for a baseline project to rebuild a 161-kV line between its Hazard and Wooton substations but denied a CPCN for a more expensive supplemental project to make upgrades at the substations. Kentucky Power, a subsidiary of American Electric Power, estimated the baseline project to cost $20 million and the supplemental project another $24 million.
| PJM
Baseline projects are administered by PJM to address violations of publicly available reliability criteria, while supplemental projects are developed internally by transmission owners and are not driven by RTO criteria. Supplementals are included with baseline projects in PJM’s Regional Transmission Expansion Plan to allow staff to identify possible reliability or operational performance issues, but they are not subject to staff oversight or approval. For years, several organizations representing demand-side interests have been clashing with TOs over the projects, arguing 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. Spending on supplementals has been on the rise, and critics believe TOs see them as an unsubstantiated way to build more. (See PJM TOs, Customers Await Ruling on Supplemental Projects.)
The PSC was unpersuaded by Kentucky Power’s contention that the supplemental made sense because engineering and construction resources would already be focused in that area. “This may speak to efficiency but not to necessity,” the commission said, noting that consideration of the projects happened through a PJM stakeholder process that FERC has since determined requires revision.
FERC ruled in February, following a 2015 technical conference and subsequent show-cause order in 2016, that TOs’ processes for receiving “meaningful input” from stakeholders on supplemental projects need additional structure to comply with Order 890 (EL16-71). TOs, through PJM, have subsequently submitted a proposed timeline for project consideration, but opponents have challenged the order as not sufficient. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)
FERC this week rejected a proposed power and gas tariff filed by the North American Energy Markets Association (NAEMA) and indicated it is likely to revoke the group’s capacity and energy tariff, which the commission accepted in 2003. The group said Thursday night it will seek an emergency stay to give it time to amend the older agreement.
NAEMA, which claims about 150 members that have 500,000 MW of generating capacity and serve more than 100 million electric and gas customers, developed the power and gas tariff with the International Energy Credit Association.
The group said the tariff, filed in January, was similar to the 2003 tariff but was updated to reflect current industry preferences for contract language and products. It intended to leave the existing tariff in place with the new one available for companies that choose to use it.
But the commission said March 19 that the tariffs should not be on file with it because NAEMA is not a jurisdictional public utility (ER18-676). “Nor does the power and gas tariff filed by NAEMA set forth any rates and charges or terms and conditions that govern the transmission or sale of electric energy. Instead, the power and gas tariff merely contains standard form bilateral sales contracts with a set of standard terms and conditions that NAEMA members may choose to use when they make sales of their own capacity and energy or natural gas to customers.”
The commission said NAEMA members that are public utilities should enter separate, standalone bilateral agreements under their own market-based rate tariffs whether or not they comport with NAEMA’s standard terms and conditions. Such transactions should be included in the utility’s Electric Quarterly Reports, FERC said.
“We make no findings about [the proposed tariff’s] specific terms and conditions or whether NAEMA members should or should not use it as a template for any market-based rate bilateral sales agreements,” the commission said.
Show Cause
FERC also directed NAEMA to show within 30 days why the 2003 tariff, which was approved by a letter order by a division director, should remain on file with the commission (ER04-22). “If such a filing is not received within the required time, NAEMA’s capacity and energy tariff will be canceled in the commission’s eTariff system,” it said. The commission did not say why it now considered the 2003 order — which NAEMA says was updated as recently as 2011 — an apparent error.
NAEMA was created in 2003 as a successor to the Power and Energy Market (PEM) of the Mid-Continent Area Power Pool (MAPP) after the group expanded. NAEMA said the 2003 tariff was a successor to one approved by FERC in 2001 for MAPP (ER01-3045) and has been updated five times since then.
NAEMA Executive Director Mike Critchley | ZEMA
Emergency Stay Sought
NAEMA attorney K.C. Hairston told RTO Insider Thursday evening that the organization will file an emergency motion seeking a stay of the show cause order to allow it to propose an amendment to the energy and capacity tariff that it said should address the commission’s jurisdictional concerns. The motion was filed early Friday.
The amendment would be a cost-based schedule, which NAEMA says will ensure the tariff falls “within the categories of agreements described by the commission in the show cause order where non-jurisdictional entities can submit tariffs on behalf of jurisdictional companies.”
The group pledged to submit the proposed amendment within 60 days.
Overwhelmingly Surprised
In the motion, NAEMA says it was “overwhelmingly surprised” by the order, claiming it contacted the commission’s Office of General Counsel regarding the jurisdiction issue and incorporated changes it suggested. The group said it realizes that OGC does not speak for the commission but “assumed that the commission would take a consistent view” with the office.
NAEMA said it had cause for the stay because “Terminating a tariff that has been repeatedly approved by the commission for over a decade and is currently used by market participants across the United States will be disruptive to the energy markets the commission regulates.”
The group also made an unusual request, saying “it will be beneficial to have a designated non-decisional commission staff member that it can consult with should issues arise” in drafting the amendment.
NAEMA, which holds regular conferences, says its goal is to “promote and facilitate a vibrant physical and financial energy marketplace” through “contacts and contracts.” Its board members include staff from ACES Power Marketing, AEP Energy Partners, EDF Renewable Energy, MidAmerican Energy, Southern Power, The Energy Authority, TransAlta Energy Marketing, WPPI Energy and Xcel Energy.
The fight between PJM transmission owners (TOs) and customers over supplemental projects isn’t over yet, despite a FERC order approving the RTO’s plan.
Both sides made filings at FERC this week in the docket determining how oversight of the local, TO-driven projects is handled (ER17-179).
PJM and its TOs said in a compliance filing Monday that they are willing to revise their original proposal to provide stakeholders more time to examine the reasons why a TO decides to pursue a supplemental project, but the RTO said many other deadlines can’t be adjusted because they must fit within the timing of its current processes. (See PJM, TOs Propose FERC Order 890 Compliance Plan.) The projects include transmission expansions or enhancements not required for compliance with regional or national reliability, operational performance, or economic criteria.
A coalition of customers calling themselves “the load group” requested rehearing of the order, arguing that it still doesn’t hold TOs accountable for their obligations under FERC Order 890. They took issue with FERC’s approval of TO-proposed language to delineate the supplemental planning process and move it from the PJM Operating Agreement (OA) — which requires a super-majority endorsement from PJM stakeholders to make changes — to a new Attachment M-3 of the Tariff. The TOs have exclusive filing rights under Section 205 of the Federal Power Act to make changes to the Tariff; other stakeholders would need the PJM Board of Managers to file a complaint under Section 206. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
Additionally, PJM’s Independent Market Monitor (IMM) has asked to intervene in the docket, wading into a clash the IMM has largely stayed out of since it was touched off with a 2015 technical conference and subsequent FERC show-cause order in 2016 (EL16-71).
Compliance Filing
PJM submitted proposed Tariff and OA revisions to address FERC’s determination that the TOs were failing to provide stakeholders with adequate notification, information, and opportunities to engage in discussions over supplementals. While PJM includes the projects in its Regional Transmission Expansion Plan (RTEP) to allow staff to identify possible reliability or operational performance issues, they are not subject to staff oversight or approval.
TOs had proposed there be a minimum of 25 days between meetings covering the three parts of project planning: assumptions, needs, and solutions. They also offered to post information to be discussed at that meeting 10 days ahead of time and allow 10 days after meetings to receive comments. Finally, they proposed a 10-day waiting period to consider written comments before incorporating their local transmission plans into the RTEP.
In response to stakeholder feedback, PJM and the TOs agreed to extend to 20 days the period before the initial assumptions meeting.
“While the [TOs] are sensitive to the desire of some stakeholders for additional time between meetings and for more time to review the materials presented for discussion at the meetings, they determined that, in most cases, longer minimum time periods would compromise their ability to coordinate the supplemental project planning process with PJM’s planning of baseline projects [that address regional or national criteria violations] for inclusion in the [Regional Transmission Expansion Plan],” the filing said. “PJM apprised the [TOs] that minimum periods between supplemental project planning meetings of more than 28 days would have the potential to cause problems by preventing effective coordination with meetings of the PJM Transmission Expansion Advisory Committee.”
TOs said the deadline for feedback on a project’s first meeting about assumptions can be pushed back “without impeding the subsequent steps in the process.”
Rehearing Request
The load group’s request argues that Attachment M-3 doesn’t resolve Order 890 issues in the first place and that it’s inappropriate for PJM to add the attachment to the Tariff rather than the OA. It also took issue with the commission not requiring TOs to provide more information to stakeholders, such as the models and data necessary to replicate the analyses identifying the need for supplemental projects. FERC also should have subjected supplementals to the same obligation-to-build, milestone requirements and PJM impact analyses as RTEP baseline projects, the group said.
The group criticized FERC for what they said was allowing TOs “to disregard their obligation to respond to comments from stakeholders.”
“The commission is not free to ignore problems with a section 205 filing that a party identifies simply because that party proposed an alternative to particular filed terms and conditions,” the group wrote. “But that is precisely what the commission did in the order. … Given the PJM TOs’ track record in failing to meet their obligations under Order 890, the PJM TOs should be required to respond to stakeholder comments. Otherwise, stakeholders will have no way of knowing whether the TOs have honored their obligation to consider these comments. … The commission should ensure that any such process is robust and offers stakeholders recourse if their comments are ignored.”
The group includes American Municipal Power, Old Dominion Electric Cooperative, the Delaware Division of the Public Advocate, the PJM Industrial Customer Coalition, the Illinois Citizens Utility Board, the Office of the People’s Counsel for the District of Columbia, and the Public Power Association of New Jersey.
The D.C. Circuit Court of Appeals on Tuesday denied several petitions for review of final EPA action on steps to cut pollution from electric power plants in order to restore to “natural conditions” the air quality and visibility in “Class I” national parks and wilderness areas.
EPA, under the 2012 Clean Air Act, issued its Regional Haze Rule, which revised its guidelines on Best Available Retrofit Technology (BART) for stationary pollution sources, usually power plants, installed before August 1977. The new rule also specified that the agency’s 2011 Cross-State Air Pollution Rule (CSAPR) had requirements stringent and effective enough for it to serve as a better-than-BART alternative for states participating in CSAPR, thus excusing states from compliance with BART itself.
| EPA
EPA also disapproved portions of certain State Implementation Plans (SIPs), designed to achieve reasonable progress under the Regional Haze Rule because those plans relied on a soon-to-be-defunct predecessor of CSAPR, the Clean Air Interstate Rule (CAIR).
The National Parks Conservation Association and the Sierra Club challenged allowing states to treat CSAPR compliance as a better-than-BART alternative.
Multiple power companies and the Utility Air Regulatory Group, as well as the State of Texas and the Louisiana Department of Environmental Quality, challenged EPA’s disapproval of SIPs relying on CAIR as a better-than-BART alternative.
Meade and Prettyman Courthouse | DC-Circuit
“Except to the extent that the challenges are moot, we affirm EPA’s actions,” said the March 20 opinion by D.C. Circuit Court of Appeals Senior Circuit Judge Stephen F. Williams.
The three-judge panel consisted of Thomas B. Griffith and Cornelia T.L. Pillard, circuit judges, and Senior Circuit Judge Williams.
Useful Life
Dealing with the conservationists’ petition first, the opinion said that “the attack on EPA’s use of presumptive BART … is jurisdictionally foreclosed by the 60-day filing window provided by the Clean Air Act.”
Furthermore, Judge Williams described “a cavalcade of attacks on alleged modelling errors,” wherein “the conservation petitioners fix on a comment that EPA failed to address in its response to comments, specifically an assertion that EPA’s model does not take into account the remaining ‘useful life’ of specific BART-eligible sources.”
The agency did not contest that it overlooked these comments.
“It argues now — reasonably, in our view — that the effects of a plant’s useful life are too speculative to model, and not significant enough to make any modeling a useful enterprise,” said the opinion. “We see no need to remand on this point for EPA to move this bit of post-hoc rationalization into a rulemaking record.”
The conservation petitioners finally argued that, in comparing CSAPR and BART, EPA compared the wrong averages.
The court disagreed, referring to its reasoning in an earlier petition from the Utility Air Regulatory Group.
“It is in the nature of averages that some particular sites may underperform while others overperform,” said the decision. “EPA’s rule requires aggregate average improvement, and its comparison of the CSAPR-region Class I areas as well as all Class I areas nationwide was reasonable.”
State and Industry
The state and industry petitioners in essence argued that if compliance with CAIR had for years allowed them to achieve greater reasonable progress than BART would have, their continued enforcement of emissions standards in line with the now-defunct CAIR must necessarily be found an adequate alternative to BART.
“But, of course, without CAIR — which all parties agree is dead and beyond revival — there is no legal basis for a requirement that states control their sources at CAIR levels; indeed, for states that are not part of CSAPR, there is no legal basis for requiring states to participate in any haze-related interstate trading program,” said the court.
The court cannot order EPA to consider CAIR an alternative to BART without resurrecting CAIR itself, “a rule that we have already stricken and ordered to be vacated,” said the decision.
The petitioners saved themselves from mootness only by couching their request for relief as “a contingency,” said the opinion. The court denied the state and industry petitioners, saying they “can afford no relief.”
The Public Utility Commission (PUC) of Texas on Monday approved the choice of John Paul Urban as its executive director during a special open meeting.
PUC Chair DeAnn Walker said Urban will oversee “something of a reorganization” once he comes on board.
Urban brings a strong political background with him. He worked in a number of legislative positions since graduating from the University of Texas in 2000 and was the PUC’s director of government relations for three and a half years before joining NRG Energy in a managerial position.
PUC OF Texas commissioners left to right: Brandy Marquez, DeAnn Walker and Arthur D’Andrea meet on personnel matters. | AdminMonitor
“Based on his past tenure at the PUC, John Paul has an excellent grasp of the agency’s mission and a sterling reputation in both the capitol and our regulated industries,” Walker said in a statement. “We are confident in his ability to lead the agency as it fulfills its oversight role.”
Walker also announced new titles for two long-time staffers as part of the strategic alignment that Urban’s hiring will complete. Thomas Gleeson, who has been at the commission for 10 years, will become the PUC’s chief operating officer, while Stephen Journeay will become commission counselor in the Office of Policy and Docket Management.
Journeay, who sits in front of the PUC during open meetings and coordinates the work on dockets, will now report directly to the commissioners, instead of the executive director. He is a licensed attorney and professional engineer and has been with the PUC since 1996.
“When I found out he was reporting to the executive director, it didn’t make much sense,” Walker said. “He really reports to us.”
Walker also announced Andrew Barlow has been hired as the PUC’s communications director. Barlow previously served in communications roles for former Texas Gov. Rick Perry and former Texas Lt. Gov. David Dewhurst.
MISO is moving ahead with a proposal to largely recycle last year’s 15-year transmission planning predictions for use in its 2019 Transmission Expansion Plan, but some stakeholders are urging the RTO to at least expand the plan.
During a March 20 workshop to gather stakeholder input on MTEP 19, MISO Planning Manager Tony Hunziker said the futures were developed for reuse over multiple planning cycles, with small updates to cover uncertainties such as the capital cost of building generation, demand growth rate and projected fuel prices. (See MISO: Minimal Change to 2019 Tx Planning Futures.) Stakeholders generally support the idea, he said.
MISO last year created four future scenarios for use in MTEP planning, including:
A limited fleet change future, in which the fleet remains relatively static with coal units retiring at the end of their useful life;
A continued fleet change scenario, in which the grid develops according to the trends of the past decade;
An accelerated fleet change future driven by a strong economy that increases demand and motivates carbon regulations and increased renewable use; and
A future in which distributed and emerging technologies become more widely used.
MISO planners are proposing small adjustments to some MTEP 19 assumptions, namely to account for sluggish load and higher-than-expected renewable penetration.
With energy growth currently outpacing load growth, planners say MISO should abandon its previous practice of assuming energy will grow at 0.5 to 1.5 times the base growth rate (extrapolated from load-serving entities’ current forecasts) in its transmission planning, and instead plan for anything from no growth to twice the base growth rate. Preliminary demand forecasts from LSEs show a 0.3% average growth rate through 2027, down from 0.5% in MTEP 18 and 0.6% in MTEP 19, while energy is expected to grow at a 0.5% rate.
MISO staff are also considering raising projected renewable penetration by 5% across all futures — from 10-30% to 15-35% of capacity. They acknowledged that the low end of the MTEP 18 range does not reflect the number of renewables on track to complete the interconnection queue.
| MISO
The RTO also plans to update its base futures model to include planned units holding a certificate of public convenience and necessity, as well as units that have a signed generator interconnection agreement.
MISO will take stakeholder input on MTEP 19 futures through April 20 and expects to have futures finalized by September.
Fifth Future
But some stakeholders are asking MISO to create of a fifth future. Investment firm Veriquest requested the RTO develop an additional scenario that focuses on the regional siting of distributed resources, while MISO’s Environmental sector asked for a standalone future showing how possible federal or state carbon regulations drive fleet evolution.
Veriquest’s David Harlan said he’d like to see futures more informed by future capacity needs.
“I still don’t have a good picture where the source of needs is and where the capacity is,” Harlan said. He urged MISO planners to make projections to share with stakeholders about who benefits from cost-effective transmission requirements to move wind from North Dakota to Mississippi, for example.
“None of that is visible in this process,” Harlan said.
MISO Director of Policy Studies J.T. Smith said the RTO does account for future capacity movement when building MTEP models.
The Transmission Owners sector said the potential industry changes depicted in the four MTEP futures adequately capture future impacts to the transmission system. “While some of the currently defined futures, such as the limited fleet change, may not align well with the current industry projections, those futures provide valuable information … as well as provide a counter to the more aggressive generation change assumptions implemented in other futures,” it said.
Apex Clean Energy’s Richard Seide asked if MISO is accounting for commitments from utilities that intend to eliminate the use of coal, such as Consumers Energy, which recently announced its plans to go coal-free by 2040. (See CMS Energy Plans a Zero-Coal Future by 2040.)
“I don’t know how to say it, but the world has changed … and it occurred very quickly. You’re sitting on the largest queue ever,” Seide said.
Shane O’Brien, of MISO’s resource forecasting group, said stakeholders have so far said the RTO’s retirement projections are adequate. The RTO does not hold utilities to retirement announcements or include them in planning until owners submit Attachment Y retirement notices.
BOSTON — The numerous East Coast offshore wind projects being developed through individual state procurements should be viewed as regional resources, panelists told a New England energy conference last week.
The 10 GW of offshore wind slated for the region has already reached a critical mass that has lowered financing costs and promises local suppliers a real market rather than a one-off opportunity, a panel of three offshore developers and one state regulator said during the Raab Associates’ 157th New England Electricity Restructuring Roundtable on Friday.
Massachusetts in 2016 set a goal to develop 1,600 MW of offshore wind by 2030, followed last year by New York, which is targeting 2,400 MW by 2030. New Jersey this year topped both with a target of 3,500 MW by the same year.
While slightly behind Massachusetts, New York is in a hurry to get rolling and plans to issue its first 400-MW offshore wind solicitation this fall, followed by a similar one in 2019, said Alicia Barton, head of the New York State Energy Research and Development Authority. (See NY Offshore Wind Plan Faces Tx Challenge.)
“I think people are looking at this the wrong way, looking at it state by state,” Barton said. “These are all leases in federal waters and this will be a growing Northeast regional resource rather than a state-by-state resource.
Although New York’s Public Service Commission will make the final determination, NYSERDA would propose to provide eligibility to projects that can either deliver directly into NYISO or through an adjacent control area, she said.
“We are eager to send the message that all of these leaseholders should be looking at this New York market opportunity and this procurement coming up,” Barton said.
First Actor Advantage
Representatives of the three developers who bid into Massachusetts’ offshore wind solicitation in December supported Barton’s regional resource theme, but each would first like to win the Massachusetts contract.
Orsted North America President Thomas Brostrom said his company will soon announce the first offshore wind factory in the U.S., to be located in Massachusetts. He said Orsted has “entered into an exclusive arrangement with a very large and recognized European manufacturing company” for the facility.
For the solicitation, Orsted partnered with Eversource Energy to form Bay State Wind, which proposed a 400-MW or 800-MW wind farm 25 miles off New Bedford, to be paired with a 55-MW battery storage facility.
“You create an industry when you have volume and pipeline,” Brostrom said. “You have basically a pipeline of 10 GW; that’s why we think we can create a local supply chain now.”
The growing reality of a Northeast offshore wind industry is already influencing bankers, who have quickly reduced the cost of project financing, he said.
In its initial request for proposals in its 83C solicitation last July, Massachusetts sought a minimum of 400 MW of offshore wind but said it would consider bids of up to 800 MW if it determines that a larger proposal “is both superior to other proposals submitted in response to this RFP and is likely to produce significantly more economic net benefits to ratepayers.”
| Deepwater Wind
The three developers, Bay State, Deepwater Wind and Vineyard Wind (the last of which is a joint venture between Avangrid Renewables and Copenhagen Infrastructure Partners), placed their bids in December and the state will announce winners on April 23, with contracts to be submitted at the end of July. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)
Brostrom presented Orsted as the global leader in offshore wind, but Matthew Morrissey, vice president of Deepwater, said his company was the leader in the Americas, having built the 30-MW Block Island project, the only offshore wind farm operating in the U.S.
Deepwater also signed a contract with the Long Island Power Authority last year for the 90-MW South Fork project, scheduled to become operational in 2022.
In Massachusetts, Deepwater proposed two versions of Revolution Wind, a 200-MW wind farm consisting of about 25 turbines, or one double that size.
“Revolution Wind contains a very innovative, expandable transmission system, a pumped storage offering and, for a project of this scale, enormous economic impact,” Morrissey said. “The Brattle Group provided us with a study — 2,700 jobs, $300 million in economic impact, and we are committed to delivering our power in 2023.”
Deepwater’s proposal includes an agreement with the largest hydroelectric pumped storage facility in New England, the 1,200-MW Northfield Mountain station operated by FirstLight Power Resources.
“The reason why timing matters here — Alicia said it’s a regional industry and I fully agree with that — but the reality is that the first projects will decide where the first part of the supply chain goes,” said Lars Pedersen, CEO of Vineyard Wind, which submitted proposals for 400-MW and 800-MW wind farms with approximately 50 and 100 turbines, respectively. “And if you follow the logic from Europe, the more of a head start you get, the more likely you are to get more of the supply chain.”
There will be supply chain up and down the East Coast, as there should be, Pedersen said, but Massachusetts has an “incredible” starting advantage with the harbor in New Bedford. He said that synergies on the transmission side of the project would enable his company to build an 800-MW line for essentially the same cost as a 400-MW one.
There’s more to transmission planning cost containment than simply comparing estimates among proposals, stakeholders learned last week at a special session of the PJM Planning Committee on the issue.
While all sides presented differing opinions, they also seemed to strike a conciliatory tone.
Staff highlighted procedural and process challenges of adding cost containment as a factor in decisions, including the potential impact the extra analysis would have on the timing of developing planning models. They also explained that project costs often must be considered as a range, rather than a specific number, which complicates comparisons.
LS Power’s Sharon Segner walked through the final two of four templates her company has proposed to help PJM standardize its comparison of transmission proposals based on several factors, including transparency, the strength of the cost-containment proposal and developers’ rate requirements. Her cost-cap analysis, for example, would create a checklist of attributes, and proposals would be categorized based on how many of those attributes PJM believed each one had.
“If it’s a weak cost cap, it’s essentially treated as a cost estimate,” Segner explained, noting that estimates would calculated based on the in-service year rather than at the time of the proposal.
“We want a better understanding about how PJM values cost containment. … From my company’s standpoint, we think there needs to be improvement [in the PJM comparative cost analysis] from the status quo,” she said. “There’s been a lot of good points raised by the transmission owners in saying … these projects have to meet the technical need and they have to solve the technical problem. … That is my company’s position as well.”
A series of events at January’s Markets and Reliability Committee meeting culminated in the issue going back to the Planning Committee for additional consideration and LS retaining control of the main proposal that the MRC will consider. To ensure its proposal has enough support to be implemented, LS narrowed the focus of revenue requirement caps to include just total all-in return on equity and capital structure cap proposals and removed the ability to offer caps on operations and maintenance costs. A representative for NextEra Energy supported removing the operations and maintenance cost-cap option. The proposal goes back before the MRC at its May meeting. (See “Transmission Flashpoint,” PJM Markets and Reliability Committee Briefs: Jan. 25, 2018.)
Transource Energy’s Brian Weber made a presentation that endorsed some of the LS goals but also opposed the overall proposal. He said it would put the focus on cost containment and “severely limit” what developers offer, moving PJM away from the “creative solutions” of the sponsorship model for transmission planning and toward the procurement model used in other RTOs/ISOs.
PJM’s sponsorship model is similar to that used for architecture proposals, where bidders are encouraged to develop their own creative solution to necessary criteria and staff are prepared to consider a wide range of potential factors. The procurement model is more like the bidding process for construction contractors, where the design has already been chosen and applicants are mostly competing on cost. A hybrid approach that tries to focus on both creativity and cost could limit the ability to achieve either of them.
RTO staff underscored the implication in their analysis of the changes necessary to consider cost-containment factors.
“Almost everyone else in the industry has one bucket of risks,” PJM’s Mark Sims said. “It adds a dimension to the level of analysis that PJM has to do.”
“I think the pragmatic reality of this is that developers will limit their submissions” due to their project designs being subsequently awarded to undercutting competitors, Weber said, adding that the plan “provides pretty significant disincentive to provide value” through creativity.
Erik Heinle with the D.C. Office of the People’s Counsel praised the technical creativity and asked why it couldn’t be replicated on the financial side.
“Great technical flexibility should be matched with flexibility and creativity in the cost arena as well,” he said.
“There is a difference between creativity and blind risk taking,” Weber responded. “Which risks should developers be expected to take? They should be expected to take the risks that they can control.”
Earlier in the meeting, PSEG Services’ Vilna Gaston had said she hoped that incorporating those cost-focused measures wouldn’t lead to a situation like the fatal bridge collapse in Florida on March 15. Ruth Ann Price with Delaware’s Division of the Public Advocate agreed and noted that media coverage showed the bridge contractor had several past successes along with several safety complaints.
Weber touched on this concern in his response to Heinle, noting that he has seen developers take risks in their cost-capped agreements filed at FERC and that he is confident they could not have had the time to perform the due diligence necessary to ensure they’re doing it correctly.
Building Consensus
Alex Stern with Public Service Electric and Gas presented transmission owners’ analysis of how easily the current proposals could implement design components that were previously identified. The analysis found that PJM’s original proposal could implement the principles with relative ease; however, it was vetoed at the MRC meeting in January.
Stern said he “fully respect[s]” concerns about gold-plating the system but acknowledged that “PSE&G would probably be at a competitive disadvantage because we’re not going to lower our standards for the customers of our state and anything we’re involved in … to the minimums that were set in [the Designated Entity Design Standards Task Force]. We’ll try to abide by what we believe are the right standards.”
He said a reasonable alternative would be limiting cost caps to construction costs.
“We’re not supportive of cost caps. Having said that, as part of the negotiation and consensus building, we were willing to try to consider taking that step. … I don’t like it, but I would concede … that it’s probably the one that provides bang for the buck to the ratepayer with an ability to track and achieve objectives. It’s probably the most enforceable,” Stern said, suggesting that implementing cost containment is such a big change that it should be eased into slowly.
“The sponsorship model might not be the best model for complex cost caps and there are challenges. I’m not suggesting it’s not doable; I’m suggesting there’s more challenges with it,” he said. “And that begs the question, do we change up the paradigm to facilitate broad-based cost caps recognizing there’ll be impacts to [the Reliability Pricing Model], they’ll be impacts to the [Regional Transmission Expansion Plan], there’ll be impacts to the interconnection queue … or do we start smaller and see how things work first?”
Heinle and Price urged implementing some way to standardize comparisons so their offices have a better chance to engage in the process. Price said staff in her office who don’t fully understand the process will immediately decline expensive projects, “so I need information to convince them.”
“If we compare apples to apples to apples, it becomes a lot easier,” she said. “I think most offices want to be actively involved in projects in their regions, but they need to the tools to be reasonably [informed].”
PJM’s Steve Herling said the process is already completely optimized and there is no lag time available for additional analysis on understanding and comparing values.
“There comes a time where there’s nothing left you can do. … You’ve got a fixed start time and a fixed end time and everything you add has to fit in between” to finish the annual RPM case build, he said. “We don’t believe you can fit it in the time frame you have. There is more work required than can be fit into this schedule.”
He pointed out that it might not be possible to standardize the process to show whether costs are comparative costs.
“There are going to be times when something is a little more than you need and there’s going to be times when it’s a lot more than you need. People make proposals. Our job is to figure out whether it’s a little more than we need or a lot more than we need and then figure out is the additional cost worth it,” he said.
The New York Public Service Commission on Thursday ruled that upstate municipal power authorities can charge higher electricity rates to cryptocurrency companies in order to prevent disproportionate increases in local retail rates.
The intense computer processing by cryptocurrency companies, such as Bitcoin miners, requires large amounts of electricity, prompting them to move their server farms upstate for the relatively cheap hydropower.
The order (18-E-0126) cited the situation in Plattsburgh, where monthly bills for average residential customers increased nearly $10 in January because of two cryptocurrency companies operating there.
The New York Municipal Power Agency, an association of 36 municipal power authorities in the state, petitioned the commission regarding concerns that these high-density load customers were having a negative impact on local power supplies.
Cryptocurrency companies look for commercial or industrial facilities where they can access the large amounts of power required for their banks of computers to create — or “mine” — digital currency.
The commission “must ensure business customers pay an appropriate price for the electricity they use,” said PSC Chair John B. Rhodes. “This is especially true in small communities with finite amounts of low-cost power available.”
In some cases, such currency miners account for 33% of a municipal utility’s total load, an “extraordinary amount” of power for a single customer to use, the commission said. By comparison, a large paper manufacturer employing hundreds of workers might use one-quarter the amount of electricity per square foot of such customers.
PSC Slashes National Grid Electric Rate Increase
The PSC approved three-year electric and gas rate plans for National Grid that came up far short of the company’s requests.
The ruling (17-G-0239) limits electricity revenue increases in the first year to only $43 million (1.7%), rather than the $326 million (13%) sought by the utility. Natural gas revenue increases in the first year were capped at $13 million (2.4%), compared to the requested $81 million (14%).
A typical residential customer using 600 kWh of electricity per month under the new rate plan would see a total monthly bill increase of $2.22 (2.9%) in the first year starting in April 2018, $3.03 (3.8%) in the second year and $3.25 (3.9%) in the third year. Eligible low-income electric customers will see a bill reduction of up to 55%.
The plan “includes a nation-leading affordability policy that substantially lowers bills for most low-income customers,” Rhodes said. “It moves forward the state’s climate agenda by expanding energy efficiency while funding non-wire alternatives and other REV-like initiatives for smarter investments.”
PSC Continues Crackdown on ESCOs
The commission ruled to restrict three energy service companies (ESCOs) from serving low-income customers while granting a fourth company its petition to serve them after demonstrating that it could guarantee a 1% savings against the utility price.
The March 15 actions (17-G-0239) included suspending the ability of Flanders Energy to market to and enroll new residential and nonresidential customers and directing the company to refund any overcharges to customers that it enrolled without proper authorization. Flanders does business in Consolidated Edison’s service territory.
The commission also denied separate petitions from Drift Marketplace and M&R Energy Resources for rehearing on original orders denying the companies’ requests to serve low-income customers. Neither company was able to demonstrate how it was going to guarantee savings, the rulings said. Drift does business in Con Ed’s territory, while M&R operates in the Central Hudson Gas & Electric and Orange & Rockland Utilities areas.
“Our ongoing efforts to reform the ESCO market remains a priority,” Rhodes said. “In instances where an ESCO proves they are fair to customers, we allow them to continue their activities in New York to bring choice and energy services to customers.” (See NYPSC Limits ESCO Service, Sets New DER Compensation.)
The commission approved New Wave Energy’s petition, which stated the company will immediately assign all its customers that participate in the utility assistance program to its guaranteed savings product. New Wave operates in the National Grid, New York State Electric and Gas, National Fuel Gas and Rochester Gas & Electric service territories.
The state’s Department of Public Service has provided evidence that many ESCOs have been significantly overcharging many mass market customers. It has also found many ESCOs have abused customers via high-pressure and deceptive sales tactics, teaser contracts and exploiting vulnerable elderly, immigrant and low-income populations.
PSC Approves Tier 2 Changes to CES
The PSC expanded Tier 2 of the state’s Clean Energy Standard, changing Maintenance Tier eligibility to include certain renewable facilities in operation prior to Jan. 1, 2015, and establishing delivery requirements into New York consistent with those for Tier 1.
The order (15-E-0302) applies only to eligible, pre-existing renewable facilities and expands the number of projects eligible for funding under the program in cases of need. The commission also increased the size threshold for eligible existing hydropower facilities from 5 MW to 10 MW, and provided for a streamlined review process, as well as a standard contract term of three years with the potential for contract renewals.
The commission said the changes will reduce the administrative burden on facilities seeking maintenance support and will better reward the environmental contributions of existing baseline renewable resources.
PSC Hems on Public Policy Tx Planning
The commission on Friday declined to identify and refer any public policy transmission planning requirements to NYISO.
The March 16 order (16-E-0558) directed DPS staff to work with the ISO and the New York Transmission Owners to identify potential transmission constraints on the bulk and non-bulk systems that may warrant the future identification of a public policy requirement, considering current and projected resources.
| NYSEG
The commission said that while it “recognizes that there are certain regions, such as the northern and southwestern parts of the state, where additional transmission facilities may support the deployment of renewable resources, the extent and magnitude of such needs requires further consideration.”
NYISO’s Tariff, approved by FERC, says that the PSC may identify which public policies, if any, constitute requirements; if the commission identifies such a need, the ISO will then solicit and evaluate proposed solutions to it.
ISO-NE’s draft 10-year Capacity, Energy, Loads and Transmission (CELT) forecast is reducing projected summer loads in 2026 by nearly 6% in part because of a sharp increase in projected energy efficiency, RTO officials told the Planning Advisory Committee on Thursday.
The draft 2018 CELT reduces the net annual energy forecast by 4.5% lower in 2025 with the net summer 2026 50/50 forecast reduced by 6.0% and the summer 90/10 forecast cut by 5.8%.
The behind-the-meter solar photovoltaic forecast for 2026 is about 0.6% higher, with energy efficiency boosted by 16.2%. The new report foresees about the same regional economic growth through 2026 as last year’s forecast.
The gross 50/50 load forecast — calculated before reductions from passive demand resources (PDR) and behind-the-meter PV — was cut by 2.7%, and the gross 90/10 forecast was 2.8% lower. The gross annual energy consumption forecast increased by 0.3%.
ISO-NE’s draft 2018 CELT report increases the gross annual energy consumption forecast by 0.3% over the 2017 study. | ISO-NE
The solar PV forecast included the expected impact of the tariffs imposed on solar panels by the Trump administration. It also includes a 0.5%/year PV degradation rate to account for solar panels’ declining conversion efficiency over time, based on research by the National Renewable Energy Laboratory.
The RTO develops the CELT 10-year forecast as part of its annual forecast process.
The finalized forecasts will be shared at the April 26 PAC and published by May 1.
Update on Transmission Projects
ISO-NE has put 22 upgrades in service since October, the RTO said in its transmission projects and asset condition update, including the new Scobie–Tewksbury 345-kV line and five other projects in the Boston area.
The RTO reported an $11.9 million increase in the estimate cost for Project 945–Adams in Central Western Massachusetts (installing two new 115-kV breakers and replace two existing 115-kV breakers and associated line relocations). The cost increased because of “an enhanced understanding of the multiple site condition impacts on the construction plan,” the RTO said.
That increase was more than offset by a $12.3 million reduction in the estimated cost of Pittsfield/Greenfield Projects 1662, 1664, 1665 and 1663 because of “project cost alignments.”
No new reliability or market efficiency-based transmission system upgrades have been added to the Regional System Plan project list since October. However, 36 new projects totaling $549.5 million have been added to the Asset Condition list, largely for the replacement of aging infrastructure.
Eastern Connecticut 2027 Needs Assessment
The PAC heard an update on the 2027 Eastern Connecticut (ECT) Needs Assessment, which is evaluating reliability needs for the 10-year period extending until 2027.
The draft needs analysis found violations of low-voltage and high-voltage reliability criteria for first and second contingencies as well as some severe thermal violations in some areas following second contingencies. All the violations were also found to be present in 2020.
ISO-NE announced the needs analysis last June. The previous ECT 2022 Needs Assessment report was finalized in June 2015 but work on solutions to address the region’s time-sensitive needs were suspended in February 2017 pending a review of RTO criteria, assumptions and methodologies impacting needs assessments and solutions studies.
The RTO said the review had “sufficiently progressed” to allow initiation of the new study.
The final scope of work was posted earlier this month, along with responses to stakeholder comments.
The study area is a rectangle bounded by the Long Island Sound on the south and the Massachusetts border on the north, with the eastern boundary the Rhode Island border and the western boundary just west of New London.
| ISO-NE
“This area hasn’t been studied in a long, long time,” said Brian Forshaw, a consultant for Connecticut Municipal Electric Energy Cooperative (CMEEC). “So, we’re glad to see things are progressing from a needs assessment to solutions studies.”
He said, however, that the needs assessment was “more limited than it should have been” and criticized the “top-down” load forecast.
The finalized needs assessment will be posted by May 31. The RTO will work with Eversource Energy and CMEEC to address the needs on their transmission systems.
Eversource Equipment Replacements
Eversource made a presentation on the replacement of its Montville 16X 115/69-kV transformer, which is at its end of life after 67 years. Total project cost is estimated at $6.3 million (-25%/+50%).
The company also provided an update on replacement of the Card Street 11F-5X autotransformer, which was originally presented in September.
The September PAC presentation recommended its replacement with a three-phase spare unit located at the Montville 4J Substation. Eversource said it conducted a re-evaluation that determined the summer long-term emergency rating of the replacement could be increased from 458 MVA to 512 MVA. The existing autotransformer is rated at 491 MVA. The estimated cost remains $8.6 million (+50%/-25%).
Transmission Planning Technical Guide
ISO-NE is continuing its revisions to the Transmission Planning Technical Guide, which was reorganized last year to a new format with four main sections: Introduction, Modeling Assumptions, Reliability Criteria and Guidelines, and Analysis Methodology.
Revision 2 was posted on the ISO website on Nov. 14, 2017.
Staff is now updating the appendices for consistency with the RTO’s style guide and publication template:
App. A – Terms and Definitions (Expected Q2 2018): Adding/removing terms and definitions; adding references to NERC and Northeast Power Coordinating Council glossary of terms.
App. B – Fast Start Generation List: Retired after change to probabilistic methods for base case dispatches of transmission needs assessments and solution studies.
App. C – DR Modeling Guide (Expected Q2 2018): New terminology associated with price responsive demand (PRD).
App. D – Damping Criteria: Retired after criteria moved to Section 3.3.3 of Technical Guide.
App. E – Voltage Sag Guideline (Expected Q2 2018): Update to clarify methodology.
App. F – 2000 STF Memo (Draft Posted March 2018): Updated diagrams for clarity.
App. G – Phase Shifter Guide (Draft Posted March 2018): Changed name from Modeling Guide to Phase Shifter Guide to focus on content of appendix; remove Sackett Phase Shifter and 3rd Waltham Phase Shifter; update all descriptions to match current operating practices.
App. H – No-Fault Contingencies (Draft Posted March 2018): Updated to current version of Planning Procedure No. 3.
App. I – Transfer Methodology (Draft Posted March 2018): Reorganized structure to align with Technical Guide format; new terminology associated with PRD.
App. J – Load Modeling Guide (Draft Posted March 2018): Added descriptions for solar PV modeling; added equations to explain methodologies; new terminology associated with PRD; adding Area-Owner-Zone-Bus assignments.
Stakeholders can provide comments for 15 days after the posting of each document on the PAC website to PACMatters@iso-ne.com. Comments on Appendices F, G and H are due April 3.
The PAC’s next meeting is April 26 at the Doubletree Hotel in Milford, Mass.
