Stakeholders representing load interests minced no words in a letter to PJM’s Board of Managers that criticized staff for rebuffing manual revisions they argue would increase transparency on transmission owners’ supplemental projects.
Signed by more than a dozen utility companies and state agencies — including American Municipal Power, Old Dominion Electric Cooperative, Kentucky’s Office of the Attorney General, the Delaware Department of Justice and the D.C. Office of the People’s Counsel, among others — the Feb. 8 letter accuses PJM of shirking its responsibility as an independent regional planner. It says the RTO failed to thoroughly vet the necessity of supplemental projects, which are managed by TOs and not deemed necessary for compliance under the RTO’s reliability, operational performance or economic criteria.
According to an AMP analysis, TO-requested projects totaled $7.2 billion in 2018, with nearly 80% classified as supplemental — a 219% increase over 2017. Meanwhile, PJM identified $560 million in baseline projects, which are those needed to solve future reliability and congestion issues.
“To be clear, the process as PJM staff is currently implementing it is not providing an adequate level of transparency,” the letter reads. “PJM is falling short of its requirements.”
Supplemental projects have consistently outpaced baseline projects in PJM’s Regional Transmission Expansion Plan, according to AMP. | AMP
Manual 14B Dispute
At last month’s Markets and Reliability Committee meeting, PJM rejected two paragraphs in a set of revisions that stakeholders approved for inclusion in Manual 14B: PJM Region Transmission Planning Process. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
The paragraphs came from an AMP proposal — designed to address load interests’ concerns — that said supplemental projects “should be based on written articulable criteria, models and guidelines that are measurable and, to the extent available, quantifiable (e.g., asset replacement prioritization) so stakeholders can replicate TO planning decisions and validate their proposed solutions.” AMP cited the transparency principles in FERC Order 890, saying TOs should disclose asset-specific condition assessments and the criteria and models supporting supplemental projects.
Aaron Berner, PJM’s manager of transmission planning, called the disputed text an “overreach” of the RTO’s Regional Transmission Expansion Plan, which he said is limited to studies of load flows, short circuits and stability.
PJM Vice President of Planning Steve Herling later confirmed the RTO would not implement the proposed changes because they were “not consistent” with FERC rulings. “We don’t do this often, but we’re going to have to not implement what the members have approved,” he said immediately after the MRC approved the changes in a sector-weighted vote of 3.46 out of 5.
AMP’s proposal won unanimous support from the Electric Distributors and End-Use Customers sectors, 80% of Other Suppliers and 58% of Generation Owners. It was opposed by all but one member of the Transmission Owners sector.
‘Paradigm Shift’
In the letter, load interests insist PJM incorrectly interpreted federal guidance on regional transmission planning rules, describing its refusal to implement the AMP language as a “paradigm shift.”
“In light of the billions of dollars in supplemental projects proposed in recent years, it is untenable to hear that PJM believes that language such as ‘should’ and ‘to the extent possible’ is an ‘overreach’ by stakeholders,” the letter concludes. “It is equally untenable that PJM staff has no problem with disregarding the supermajority vote of the PJM stakeholders.”
PJM spokesman Jeff Shields said Wednesday the RTO remains committed to working with all stakeholders to maintain transparency and accountability. He cited its decision to clarify the term “useful life” in the manual as “not intended to indicate that facilities might be replaced solely based on them being fully depreciated.”
“The [other] manual changes forwarded to PJM are simply inconsistent with FERC’s description of PJM’s role in transmission planning,” Shields said. “PJM has exclusive purview over its manuals and is not required to introduce changes requested by stakeholders.”
In a separate letter to the board Feb. 11, the American Public Power Association (APPA) and the Transmission Access Policy Study Group (TAPS) said PJM’s refusal lacks “compelling justification.”
“The recently rejected Manual 14B revisions would have afforded stakeholders additional transparency concerning the basis, cost, timing and need for proposed supplemental projects,” wrote APPA CEO Susan Kelly and TAPS Executive Director John Twitty. “Transparency and opportunity for meaningful stakeholder participation in supplemental project planning help ensure that these projects will be cost-effective and beneficial to customers.”
The groups argued that PJM should not reject “broadly supported” manual changes designed to increase transparency around supplemental projects without “a compelling justification.”
“We urge the board to carefully consider the load group’s arguments that such a justification was lacking in the case of the rejected changes to Manual 14B,” the groups said.
The PJM Board of Managers agreed to submit staff’s revised energy price formation proposal for FERC approval, CEO Andy Ott said Wednesday.
“PJM will review the agreement language with stakeholders prior to filing, and we look forward to that opportunity,” he said in an email to members the day after the board’s meeting Tuesday. “The board thanks stakeholders for their engagement and their ongoing support on this important matter.”
He said the Federal Power Act Section 206 filing will happen within the next few weeks.
The plan, advanced at the recommendation of the board’s Competitive Markets Committee — with input from both the Independent Market Monitor and members’ Liaison Committee — includes the following from PJM’s proposal:
Consolidation of Tier 1 and Tier 2 synchronized reserve products;
Improved utilization of existing capability for locational reserve needs;
Alignment of market-based reserve products in day-ahead and real-time markets;
Downward sloping operating reserve demand curves (ORDCs) for all reserve products; and
Increased penalty factors to ORDCs to ensure utilization of all supply prior to a reserve shortage.
2 Changes
The board recommended two changes after lengthy discussions with stakeholders, including a Liaison Committee meeting Feb. 11.
The board directed PJM to adjust its assumptions regarding generator forced outage rates based on feedback from the Monitor, which said staff were being overly conservative. The board also ordered the RTO to increase the cap on demand response that may be assigned as synchronized reserves to 50% of the requirement.
PJM’s proposal replaces the current stepped ORDC with a sloped curve; the first horizontal segment would represent the minimum reserve requirement, with the downward sloping curve based on the probability of reserves falling below the minimum reserve requirement (PBMRR) in real time based on uncertainties. The PJM proposal also increases the price for the initial horizontal segment of the curve to $2,000/MWh, up from the current $850.
The filing will not include a transitional adjustment to the energy and ancillary services offset in the capacity auction.
During a special session of the Members Committee on Feb. 6, PJM’s Stu Bresler said the FERC filing will likely come in early to mid-March, with a June 1, 2020, “reasonable target” date for implementation.
Opposition Likely
PJM’s filing is certain to be opposed by load interests concerned about the cost of the changes. The proposal received only 31% support in a sector-weighted vote at the MRC, with no ‘yes’ votes from End-Use Customers and only one vote out of 28 from Electric Distributors. It was supported by 60% of Transmission Owners and almost half of Generation Owners and Other Suppliers.
A PJM white paper published in December projected that staff’s plan — before the two changes ordered by the board — would boost energy and reserve market revenues by $1.92 billion annually, with energy revenues up $1.8 billion (increasing average LMPs by $2.27/MWh) and reserves increasing by $190 million. Uplift was projected to drop by $70 million.
The RTO expects the additional costs will be at least partially offset by reduced capacity costs. It said the most optimistic case would result in annual cost savings to consumers of $350 million.
“A potentially more realistic outcome is that these changes will increase costs to loads in the range of $700 million,” the RTO said. “PJM believes these changes are justified because much of the reserve capability PJM has today is either undercompensated or not compensated at all.”
“PJM has detailed its concerns with current energy and operating reserve pricing mechanisms but has not justified the urgency of resolving these concerns, established the operational and cost effectiveness of its solutions, or adequately evaluated the risks and rewards of its proposed reforms,” said Michael Richard, president of the Organization of PJM States Inc. (OPSI) in a letter dated Jan. 29. “It seeks to institute new market structures under an unnecessarily rushed timeline, allowing little opportunity for its staff to generate the analyses necessary for stakeholders to fully understand the potential impacts these proposals will have on market sellers and consumers, gauge the reasonableness of the proposals or develop alternatives.”
The Sustainable FERC Project, meanwhile, filed a letter of opposition Feb. 4 on behalf of the Sierra Club Environmental Law Program, the Union of Concerned Scientists and the Clean Energy Program that said proposals by PJM and others “neither consider the existing demand response reserves committed on the system, nor provide a mechanism to compensate those demand resources for the reserve services they are providing.”
“PJM’s energy reserve reform package would unacceptably delay fully and efficiently utilizing the capabilities of clean energy technologies to serve system needs,” the letter reads. “Over 68% of load served in PJM is located in states that have clean or renewable energy targets that become increasingly ambitious in coming years. It is no longer acceptable for consideration of clean energy technologies to be relegated to an afterthought.”
The board also heard earlier from executives of FirstEnergy, Exelon, Duke Energy and Public Service Enterprise Group, who criticized the RTO for failing to implement energy and capacity market rule changes despite a decade of stakeholder discussions. (See Utility CEOs Urge PJM Board to Act on Price Formation.)
Nearly 40 people braved a snowstorm Tuesday to testify on a bill that aims to put some of New York’s ambitious decarbonization goals into the statute books.
The testimony over the draft Climate and Community Protection Act (S7971A) was part of the New York State Senate’s first-ever hearing on climate change, held by the Committee on Environmental Conservation and chaired by Sen. Todd Kaminsky (D). Control of the Senate this year passed to Democrats from Republicans who had declined to take up the issue.
NYSERDA CEO Alicia Barton testifies at the New York State Senate hearing on climate change on Feb. 12, 2019. | NYSERDA
Last month, Gov. Andrew M. Cuomo vaulted the state ahead of all others in renewable energy targets by pledging to erase the state’s carbon footprint by 2040 and nearly quadrupling its offshore wind energy goal to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)
Alicia Barton
“Here in New York, public policy is informed by science, and we are collectively committed to taking action to address the climate crisis,” Alicia Barton, CEO of the New York State Energy Research and Development Authority, said at the hearing. “The discussion today is not about whether to act, but how best to act.”
Todd Kaminsky
The proposed bill specifically targets sectors other than the electric generation sector, Kaminsky pointed out. He asked Barton whether lawmakers should place emission caps on transportation and buildings, for example.
“Our efforts are much more mature in the electric sector,” Barton said, adding that similar work and analysis would be needed in other sectors, including “pushing the markets to advance more quickly… in building decarbonization and electrification and emissions reduction in the transportation sector.”
70% Renewable by 2030
The cornerstone of the new state goal: to increase of the state’s Clean Energy Standard mandate from 50% to 70% renewable electricity by 2030.
The governor’s proposal “sets the 100% clean electricity standard by 2040 but also directs the Climate Action Council to develop a roadmap to a carbon-neutral economy,” Barton said.
Last fall’s report by the U.N.’s Intergovernmental Panel on Climate Change “stated that there is no historic precedent for the magnitude of changes that are necessary,” Barton said. “The good news is that we have been making progress faster than we thought just a few years ago … technology has been breaking our way and costs have been breaking our way.” (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
Brian Kavanagh
She said nobody foresaw the incredible cost declines in technologies such as offshore wind even a few years ago, “and I think we have every reason to hope that we will see those same transformations take place in transportation and in the building sector.”
Sen. Brian P. Kavanagh (D) asked Barton whether the administration would think it “imprudent to try to develop legislation” while the state agencies are working out their plans to achieve the state’s energy goals.
Barton declined to speak for the governor but said “given where we are today, doubling down and accelerating quickly in the electric sector is something that we believe is technologically reasonable” and cost-effective.
She added that New York also has “the most aggressive energy storage targets in the country” and that many projects should start to come online in the second half of the year.
Julia Salazar
Sen. Julia Salazar (D) asked what the state is doing to protect people of color and low-income residents, who tend to be impacted most by higher electricity rates. Barton said NYSERDA is working on a number of programs “across the board to make sure that low-income New Yorkers have access to solar energy and other new renewable energy resources.”
Brad Hoylman
Bill sponsor Sen. Brad Hoylman said the draft legislation “aims to build up those communities through direct targets in terms of prevailing wage, apprenticeship utilization and the like.”
“Does the governor’s plan have those kinds of good job-making targets?” he asked Barton.
“Already today NYSERDA has taken the step of requiring prevailing wage under our large-scale renewable energy solicitations,” Barton said. “The state’s request for proposals for offshore wind energy was the first in the country to require a negotiation of project labor agreements, and the agency has allocated $70 million for workforce training.” (See New York Plans for Wind Energy, Related Jobs.)
No Rolling Blackouts
Peter Iwanowicz
Peter Iwanowicz, director of the Environmental Advocates of New York, advised legislators not to be swayed by naysayers.
Iwanowicz recounted how New York’s power companies provided three warnings before the state joined in creating the Regional Greenhouse Gas Initiative: “First, RGGI was going to drive prices through the roof. Second, there’d be blackouts in New York City. Third, and this is really unbelievable, but I was told this directly, power companies were going to shut down in New York and move to Pennsylvania just to avoid RGGI.”
Darren Suarez
Darren Suarez of the Business Council of New York State said that its members oppose the legislation and that if measures taken “in New York result in increased emissions elsewhere in the world, we’ve done nothing to solve the problem.”
“The European experience demonstrates that well-intentioned environmental policies can result in higher energy production costs, driving carbon leakage and output leakage,” Suarez said. “To those who say the legislation is aspirational … this is not a goal, it’s a law, and the law will require that emissions be 50% below 1990 levels by next year.”
Roger Downs
“The pace at which we should make these changes has been hotly debated,” said Roger Downs of the Sierra Club. “In some ways it is not unlike evacuating people from a burning theater. Moving too fast in a panic has the same dire consequences as moving too slowly.”
Sam Wade
The committee heard from foresters, forest product makers, bird lovers, and also from a Californian who supports running heavy industrial vehicles on renewable gas.
Sam Wade of the Coalition for Renewable Natural Gas, who ran California’s low-carbon fuel standard program for the past 10 years, testified that “taking one big diesel rig off I-87 today is the carbon emissions equivalent of taking 119 gasoline-powered cars off the road.”
American Electric Power will buy Sempra Energy’s renewable business in a $1.056 billion deal that will triple AEP’s renewable portfolio, the companies announced Tuesday.
Sempra’s Sempra Renewables subsidiary owns all or part of seven wind farms and one battery installation in seven states, with a total capacity of 724 MW. Five of the wind farms are jointly owned with BP Wind Energy, which will retain its ownership share.
Sempra Renewables owns the Apple Blossom Wind project in Michigan and the Black Oak Getty Wind project in Minnesota. It holds interests with BP in Colorado (Cedar Creek 2 Wind), Hawaii (Auwahi Wind, which also includes battery storage), Indiana (Fowler Ridge 2 Wind), Kansas (Flat Ridge 2 Wind) and Pennsylvania (Mehoopany Wind).
The facilities have an average capacity factor of 37%. The energy is contracted out through long-term, power-purchase agreements with investor-owned utilities, municipal utilities and electric cooperatives, with an average remaining life of 16 years.
AEP will also acquire all Sempra Renewables wind projects in development.
AEP Renewables, AEP’s competitive renewable subsidiary, owns 351 MW of contracted renewable generation. It has wind and solar projects in Texas (261 MW wind), California (20 MW solar), Nevada (50 MW solar) and Utah (20 MW solar).
AEP Renewables also recently signed an agreement to purchase a 75% interest, worth 227 MW of capacity, in Invenergy’s Santa Rita East Wind Project under construction west of San Angelo, Texas. AEP will acquire its share of the project upon completion later this year. Invenergy will retain the remaining 25%.
With 1,302 MW of renewable generation in 11 states, AEP will become the seventh largest utility owner of competitive wind generation in the United States upon the completion of the Sempra transaction and Santa Rita construction.
Sempra Renewables’ Apple Blossom Wind Farm | Sempra Renewables
Following the 2018 collapse of its $4.5 billion, 2-GW Wind Catcher project, AEP said it would focus on smaller renewable projects as part of its plan to reduce carbon dioxide emissions 80% from 2000 levels by 2050. (See AEP to Focus on Smaller Renewable Projects.)
“Our long-term strategy is focused on diversifying our generation portfolio, including expanding our ownership of renewable generation,” said AEP CEO Nick Akins in a statement.
AEP’s generation capacity in 2005 was 70% coal-fueled, 19% natural gas and 4% renewable. After the Sempra transaction’s closure, the mix will be 46% coal, 27% gas and 16% renewable.
The deal includes $551 million in cash, assumption of $343 million in existing project debt and $162 million in tax equity obligation. It is part of the company’s planned $2.2 billion investment in contracted renewables by 2023.
The transaction is expected to close in the second quarter of 2019 and is subject to FERC approval and Hart-Scott-Rodino clearance.
WASHINGTON — FERC Commissioner Richard Glick on Tuesday provided some insight into the “vigorous debate” over natural gas pipeline approvals that has divided the commission along party lines.
Speaking at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit, Glick said that, by failing to consider the impact of greenhouse gas emissions when licensing pipelines, “the commission is essentially ignoring” the 2017 D.C. Circuit Court of Appeals’ order that remanded FERC’s approval of an environmental impact statement for the Southeast Market Pipelines Project. (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)
In its rejection last May of a rehearing request of its environmental assessment for Dominion Energy Transmission’s New Market Project, FERC ruled 3-2 along party lines that it will no longer prepare upper-bound estimates of GHG emissions when “the upstream production and downstream use of natural gas are not cumulative or indirect impacts of the proposed pipeline project.” (See FERC Narrows GHG Review forGas Pipelines.)
Glick, a Democrat, has issued several dissents in the commission’s approvals of gas infrastructure because of his opposition to that policy. “What gets me concerned about that is I think I get this kind of reputation as being against all natural gas pipelines. That’s just not true. That’s simply not true,” he told a ballroom of state regulators and their staff at the Renaissance Washington Hotel. “The fact is I think we need to do more analysis. … There are certainly pipelines that I could vote for. If we weigh the benefits of that pipeline versus the greenhouse gas emissions, I think that I could end up voting for them.”
Fellow Democratic Commissioner Cheryl LaFleur has voted for certain pipelines after considering their emissions but also partially dissented on those projects, noting the rest of the majority did not take emissions into account. (See Dem Dissents Show FERC Divide on Carbon.)
“I think the fact that the commission is not doing its job, we’re creating a lot of uncertainty, legal uncertainty in particular,” Glick said.
‘Not Enough Compromise’
With the death of Commissioner Kevin McIntyre, there is now a 2-2 partisan split, and Chairman Neil Chatterjee has been pulling gas items from the consent agenda at open meetings.
“I’m trying to figure out what the harm is. I think we can do the analysis. The numbers aren’t that hard to figure out,” Glick said. “I’m just trying to figure out what [the Republican commissioners’] real motivation is, and sometimes I worry it’s from an ideological perspective about climate change.”
He said the social cost of carbon is “a good tool for us to be able to determine whether an externality is significant, and if it’s significant, if it’s outweighed by the benefits” of a proposed project.
Idaho Public Utilities Commissioner Kristine Raper asked Glick whether he was concerned about a lack of plaintiffs to appeal FERC decisions on which he dissented. He said “there’s a reasonable chance” some of them would be overturned by the courts because “the commission didn’t do what it was supposed to do under the various statutory requirements.”
But he noted the plaintiff in the Southeast Market case declined to appeal FERC’s order on remand upholding its original decision, in part because of a lack of resources. “That is a concern. I think you’re going to see that. There’s kind of a fatigue out there, and there’s not sufficient resources sometimes to take these cases to the courts.”
Speaking to reporters, Glick said “we’re still having discussions” about the emissions dispute. He wants the commission to repeal the policy from the New Market case, “but so far they haven’t done that, so [there’s] not enough compromise at this point.”
Despite the dispute falling along party lines, Glick defended the commission against charges of politicization. “There have been a number of articles written, and I’ve read those articles [asking] are we independent anymore? Is the Trump administration telling us what to do? Are the commissioners themselves being too political, whether it’s on the left or on the right? …
“But in reality, I think FERC itself is as independent as an independent agency can get,” he said. “And even though our decisions or our votes come down on party lines, I think among the commissioners themselves, I think there’s never really a discussion of politics.”
Twitter Spat
Asked by a reporter if there were any issues every commissioner agreed on, Glick said there were plenty, highlighting Order 841, a unanimous ruling a year ago that directed RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets.
“I’d say 90-odd percent of the votes that we have” are unanimous, Glick said.
Glick also defended the statement that he and LaFleur made Feb. 5 regarding FERC’s inaction on Vineyard Wind’s request for a waiver ahead of ISO-NE’s 13th Forward Capacity Auction. (See ISO-NE Completes FCA 13 Despite Controversy.)
Glick tweeted the statement, then Chatterjee responded with his own tweet subtly chastising his colleagues. “I do not discuss the commission’s internal deliberations with the public,” Chatterjee said. “Doing so would be highly inappropriate and might undermine the commission’s process.”
Bloomberg described the incident as a “Twitter spat.”
“I don’t think that was airing any grievances at all against the other commissioners,” Glick told reporters. “We were just expressing frustration that unfortunately, we didn’t issue an order and created some uncertainty. … I had a conversation with Chairman Chatterjee after that and explained to him that before we posted that statement, we checked with the general counsel’s office [and] we checked with the ethics adviser. … I think the chairman now understands that that was not an appropriate comment.”
Commissioner Bernard McNamee also appeared at the summit in an 11-minute discussion with Virginia State Corporation Commissioner Judith Jagdmann, but he did not discuss the gas policy dispute and left without taking any questions from the audience or reporters.
Regulators Grant Preliminary Approval to Sharyland-LP&L Projects
The Texas Public Utility Commission last week issued preliminary orders approving certificates of convenience and necessity (CCNs) related to integrating a portion of Lubbock Power & Light’s SPP load into the ERCOT system.
The commission consented to a request by the city of Lubbock and Sharyland Utilities to build a single-circuit 345-kV transmission line and associated facilities, which include an expanded LP&L switchyard. Sharyland will take care of the construction, while LP&L will own and operate the line upon its completion (Docket 48668).
The project has a total estimated cost of $65.3 million to $90.4 million. The 18 proposed routes range between 30 and 50 miles.
During its Feb. 7 open meeting, the commission also conditionally approved LP&L and Sharyland’s joint application to build a 345-kV transmission line and a 115-kV line that will eventually interconnect (Docket 48909).
Sharyland will own the 115-kV line but will share ownership of part of the 345-kV line with LP&L. The former is expected to cost $49.7 million to $61.4 million and has 14 potential routes ranging between 14 and 26 miles. The latter project has an estimated cost of $88.4 million to $103.9 million and 22 possible routes ranging in length from 42 to 53 miles.
In a memo, PUC Chair DeAnn Walker said it was inappropriate for two separate transmission lines to be filed in a single CCN application because “it raises concerns of efficient administrative processing of the cases.”
But Walker said she was willing to make an exception in LP&L’s case because severance might be too difficult at this point and the project is time-sensitive. She recommended the State Office of Administrative Hearings issue separate proposals for decisions for each line and said that future CCN applications should be split apart if more than one transmission line is included.
Sharyland had proposed a $247.5 million, 345-kV project in the Texas Panhandle that overlapped with the facilities needed to integrate LP&L into ERCOT, but predated LP&L’s move. ERCOT was unable to find the project as meeting economic needs.
The PUC must issue a final decision in both dockets by Sept. 20.
LP&L announced in 2015 that it intended to move about 70% of its load, currently provided through two long-term contracts with Southwestern Public Service (one of the contracts expires in 2021). The PUC approved the migration in March 2018. (See “LP&L Welcomed into ERCOT,” Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
PUC Puts off Final Decision on Rayburn Country
The commission debated but put off two decisions related to Rayburn Country Electric Cooperative’s proposal to move 96 MW, or about 12% of its load, from SPP into ERCOT.
At issue is Rayburn’s request that the load being transferred to the Texas grid be included in the co-op’s existing non-opt-in entity load zone (an area without retail choice), and that it be granted a good-cause exception from a four-year notice requirement for ERCOT Board of Directors approval. The commission also expressed concern that congestion revenue rights holders in the area might not have been properly notified (Docket 48400).
Following the open meeting, the PUC filed a briefing order requesting briefs from the settlement’s signatories by Feb. 26. The commission expects to file a completed order at its March 13 meeting.
Rayburn signaled its intentions to transfer the load in 2016, and late last year it reached an unopposed settlement with commission staff, Oncor and the Texas Industrial Energy Consumers that approved the transfer of the load and associated facilities into ERCOT. The agreement denied the sale of transmission facilities and associated CCN rights to Lone Star Transmission.
ERCOT and SPP did not join in the agreement, but they did not oppose it either.
Separately, the commission held off on an order approving Rayburn’s sale of a 30-mile, 138-kV line in its territory to NextEra Energy Transmission Southwest (NETS). Southwestern Electric Power Co. owns the substations at both ends of the line, and NETS plans to transfer functional control of the line to SPP when the transaction is completed (Docket 48071).
NETS has applied to become a transmission-owning member of SPP.
“I see a lot of inefficiencies,” Walker said.
Commissioner Arthur D’Andrea supports Walker’s decision, but Commissioner Shelly Botkin said she had not yet formed an opinion on the “broader issues.”
The PUC’s final order is clouded by its 2017 ruling under different commissioners that SPS does not possess an exclusive right to construct and operate transmission facilities, including new regionally funded transmission facilities, within its service area. Former Commissioners Ken Anderson and Brandy Marty Marquez had also determined the commission had the authority to grant a certificate to an entity that will provide only transmission service outside of ERCOT (Docket 46901).
“I don’t believe we have the authority to grant this,” Walker said. “I read everything in 46901. I would not have come down that way.”
“We might need time to think creatively about the best way to do this and change course,” D’Andrea said.
SPS appealed the decision in November 2017 to the 459th District Court (D-1-GN-18-000208).
Staff to Study ERS Load Resources
In other actions, the PUC:
Directed staff to open a project on emergency response service (ERS) and the potential for daily offers into the market. Walker noted some load resources are currently excluded from offering ERS because of unavailability for particular contract periods.
Delegated authority to Executive Director John Paul Urban to sign joint comments with the Texas Commission on Environmental Quality and the Railroad Commission of Texas in response to EPA’s proposal to eliminate the requirement that new coal-fired generation incorporate carbon-capture technology (EPA-HQ-OAR-2013-0495). The three agencies have joined together before to provide comments on similar legislation. (See EPA Eases Rules for New Coal Generation.)
Approved CCNs for Electric Transmission Texas’ 345-kV project in South Texas. The commission found the $44.8 million cost for 5 miles of 345-kV double-circuit line and a substation expansion to be reasonable. The area has incurred overloading since the 524-MW Frontera combined cycle generation facility began exporting its capacity to Mexico in 2016 (Docket 47973).
VALLEY FORGE, Pa. — PJM’s Planning Committee on Thursday unanimously approved a problem statement to consider granting merchant transmission developers capacity interconnection rights (CIRs) for offshore wind.
Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under the problem statement, stakeholders will consider allowing merchant transmission developers to request CIRs, or equivalents, for non-controllable AC transmission offshore, PJM’s Sue Glatz said.
The vote came after PJM officials resisted calls to broaden the initiative to also consider rules for non-controllable AC transmission facilities onshore.
“My concern is that in essence what we are doing is that we are going to prioritize the transmission facilities built out into the ocean, but we are not giving a path for the same thing to occur for facilities with future plans to connect to renewable resources,” said Ryan Dolan, director of transmission planning for American Municipal Power. “We are mitigating risk for offshore and not doing the same thing for AC onshore.”
Offshore transmission developers want to acquire CIRs so PJM can identify the necessary network upgrades.
The key difference from the normal procedure is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses. (See “PJM Ponders Rules for Offshore Wind Transmission,” PJM PC/TEAC Briefs: Jan. 10, 2019.)
PJM said the narrow scope of the problem statement addresses an immediate need from pending interconnection requests.
The RTO hopes to develop a FERC filing on Phase 1, focusing on rules for a single offshore generator lead line, by July.
Steve Herling, PJM vice president of planning, said the RTO could discuss extending similar rights to onshore developers in Phase 2 of the initiative, when it will consider networked offshore transmission for connecting multiple wind sites.
“We don’t have a fundamental issue with doing the same thing onshore … but because of the immediacy of the need, we would prefer to develop this with respect to offshore and then it would probably be a fairly straightforward extension of it in Phase 2 if there’s value of doing it onshore,” Herling said. “We do feel a sense of urgency offshore.”
PJM has targeted Phase 2 for a September 2020 FERC filing.
Quick Fix for Queue Filing Errors Endorsed
The PC approved a problem statement and solution to prevent transmission customers from falling out of the interconnection queue because of minor errors.
The one-sentence rule change allows customers 10 days to fix any deficiencies in their requests — whether they submit their application on the first or the last day of the new services request window.
PJM’s Susan McGill first presented the problem statement to the committee in January, suggesting the RTO reverse rules implemented in 2016 by the Earlier Queue Submission Task Force that didn’t allow requesters adequate time to clear errors found in their submissions. (See “PJM Seeks Fix on Queue Filing Errors,” PJM PC/TEAC Briefs: Jan. 10, 2019.) The change — intended to encourage generation customers to submit requests earlier in the six-month window — led to a 6% increase in terminated or withdrawn applications filed in the last month.
PJM is proposing to give all projects 10 days to address problems by removing the following sentence from the Tariff: “Any queue position for which an interconnection customer has not cleared the deficiencies before the close of the relevant new services queue shall be deemed to be terminated and withdrawn, even if the deficiency response period for such queue position does not expire until after the close of the relevant new services queue.”
The problem statement is scheduled for endorsement at the March 21 Markets and Reliability Committee meeting. It would be effective with queue AF1, which opens April 1.
PJM Pushes Change in Wind, Solar Capacity Measurements
PJM has decided to use effective load carrying capability (ELCC) to calculate wind and solar capacity credits, calling it a “superior alternative” to current rules using average values. ELCC measures the additional load that a group of generators can supply without a reduction in reliability.
The new methodology combines wind and solar capacities in one calculation that is later prorated. Tom Falin, PJM’s director of resource adequacy planning, said this process sets wind and solar factors to 12.3% and 41%, respectively.
“I think all along we should have done this in a composite manner,” he said. “Why? Because both wind and solar are going to be around to serve PJM load. It’s a model of the entire system.”
Falin said considering the total amount of intermittent generation is crucial to the process, noting the “point of ELCC is to really figure what’s the incremental value of a new type of unit when you add it to the existing fleet.”
Some stakeholders disagreed with PJM’s decision to calculate solar and wind capacities together, citing their different characteristics.
“I agree they are both going to be here, barring some disaster,” said John Brodbeck of EDP Renewables. “We’ve been working them as separate numbers. … I haven’t noodled through what this does here. It just seems to mix apples and oranges.”
The new rules will be included in Manual 21 changes that will be presented to members in March. PJM wants to request MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August. They would not affect UCAP values from prior auctions.
Holistic Review of RTEP Removal Suggested
PJM said Thursday it’s considering drafting a problem statement regarding how projects get removed from the Regional Transmission Expansion Plan, suggesting the process needs a “holistic” review.
PJM’s Aaron Berner said because of differing regulatory requirements in its 13 states, the RTO has dealt with cancellations on a case-by-case basis. Cancellations can result from a reduction in load forecasts — eliminating the need for a project — or because developers are unable to get state siting approval.
“In the past there have been changes to the load profile or the actual load forecast that’s resulted in a reduction for a need for reinforcement on the system, and we have pulled some baseline upgrades based on that,” he said. “Primarily, it’s our need that drives our decision around the various insertions and removals of the project.”
The issue arose after Sharon Segner, vice president of LS Power, proposed an amendment to Manual 14B: PJM Region Transmission Planning Process specifying that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project.
“It’s very important that the rules be very clear with how projects are added to the RTEP and how they are removed,” Segner said. “We stand behind the viewpoint that PJM should be a strong regional planner and have complete authority over the regional and supplemental process.”
Segner first presented the new manual language during the Jan. 24 MRC meeting as a friendly amendment to a proposal from American Municipal Power to increase transparency of supplemental project planning. AMP accepted the amendment as friendly. Despite winning a majority of stakeholder approval, PJM declined to implement the entirety of the AMP proposal, calling it an overreach of the RTEP. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
PJM said it will discuss the issue further with stakeholders after identifying requirements in the Operating Agreement, Tariff and manuals that spell out when projects should be removed from or added to the RTEP.
Segner declined to say whether she will seek a vote on her language at the MRC. “I’m still getting feedback; the purpose of this discussion was to talk through substance. It’s not a procedural discussion today,” she said. “PJM said they’re taking this [PC discussion] under advisement. That’s what LS Power is doing as well.”
Dominion, ATSI Present Supplemental Projects at TEAC
TOs presented two supplemental projects to the Transmission Expansion Advisory Committee.
American Transmission Systems Inc. plans upgrades to a 345-kV line between Erie, Pa., and the Perry nuclear plant in Ohio. The three-terminal line is prone to misoperations and subject to longer restoration efforts, and its relay transmission communication equipment is nearing its end of life, ATSI said. No cost was listed.
Dominion Energy Virginia presented seven supplemental project needs and one solution, a second distribution transformer at the Greenwich substation to address growing load. The $1.4 million project is expected to be complete by Oct. 15.
Dominion listed the following needs:
A third distribution transformer at the Winterpock substation;
A second distribution transformer at the Rockville substation in Goochland County;
A second 84-MVA distribution transformer at the Cumulus substation in Loudoun County;
A new Lockridge substation to support a new data center campus in Loudoun County with a total load exceeding 100 MW;
A third 84-MVA distribution transformer at the Pacific substation in Loudoun County;
A new Perimeter substation to support a new data center campus in Loudoun County; and
A new Relocation Road substation to support a new data center campus in Loudoun County with a load exceeding 100 MW.
VALLEY FORGE, Pa. — The PJM Demand Response Subcommittee would be tasked with updating the testing rules for rarely dispatched DR resources under a problem statement and issue charge presented to members Wednesday.
PJM’s Jack O’Neill told the Market Implementation Committee that the RTO’s current testing rules are based on limited demand response (LDR) requirements made obsolete by Capacity Performance.
LDR applied only to summers, non-holidays and weekends, while CP requires the resource on demand year-round. Likewise, CP events can now last up to 15 hours — versus just six under LDR — and lack LDR’s cap of 10 reductions a year.
PJM says it is concerned because load management events are “low frequency, high impact” incidents. The last recorded event, in 2013, required reductions totaling 6,000 MW across 15 transmission zones. In years when there are no events, there is only a one-hour summer test of performance.
“Testing is our fallback position when there isn’t anything to measure against,” O’Neill said.
PJM noted that DR has averaged about 123% performance in tests versus about 97% in actual events. “This indicates that testing may not reflect performance during actual events,” the problem statement says.
The RTO hopes to bring the revisions to the MIC for a first read in August, a schedule it said would allow for a FERC filing by February 2020 and a commission ruling in time for next year’s Base Residual Auction.
The daily load management test failure charge rate will not be affected by the review.
Utilities Question Primary Frequency Response Calculation
VALLEY FORGE, Pa. — PJM’s Operating Committee last week endorsed revisions to Manual 12: Balancing Operations over the opposition of FirstEnergy, which challenged the manual’s formula for judging primary frequency response performance.
Under the formula included in a newly added Section 3.6 of the manual, PJM will evaluate generators’ performance during events in which the system frequency goes outside a +/-40-MHz deadband for 60 continuous seconds and the minimum or maximum frequency reaches +/-53 MHz.
PJM’s Danielle Croop, senior engineer of operation analysis and compliance, said the formula was vetted by the Primary Frequency Response Task Force based on NERC criteria.
“We opened up our criteria to be more lenient … and we are catching as much performance as we can,” she said. “We are open to changing the formula.”
Jim Benchek, FERC and RTO market technical support at FirstEnergy, said the formula is too sensitive and could result in false failures. “We prefer not to have the formula memorialized in the manual at this time.”
He added that his company remains committed to providing PFR.
The manual changes were endorsed despite 24 objections by FirstEnergy and Duke Energy and 20 abstentions.
At the January OC meeting, American Electric Power noted that FERC’s order did not require scoring of PFR and said PJM had little stakeholder support for it. (See “The Right Metric on Frequency Response?” PJM Operating Committee Briefs: Jan. 8, 2019.)
PJM Continues Review of Non-retail BTM Generation Business Rules
PJM provided stakeholders additional background on a proposed problem statement and issue charge that could result in revised rules for non-retail behind-the-meter generation (NRBTMG).
Terri Esterly, PJM’s senior lead engineer for capacity market operations, said business rules in the RTO’s governing documents need modifications to address the growth of distributed generation. NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load; they do not participate in PJM markets but can be netted against load to reduce certain charges.
Esterly said it’s been nearly 15 years since a settlement agreement established rules for NRBTMG — long before the RTO implemented the Reliability Pricing Model and Capacity Performance and took on several utility companies as members, including American Transmission Systems Inc., East Kentucky Power Cooperative and Duke Energy’s Ohio and Kentucky divisions.
Under existing rules, NRBTMG must operate at full output during the first 10 instances of maximum emergency generation conditions between Nov. 1 and Oct. 31. However, it’s not clear in Manual 13: Emergency Operations what procedures trigger this requirement.
Likewise, the RTO doesn’t know how close the grid is to exceeding the 3,000-MW NRBTMG cap set in 2005. PJM estimates put this value closer to 4,600 MW, but incomplete public records make it difficult to determine an exact figure.
PJM first proposed reviewing NRBTMG rules during a Jan. 8 Operating Committee meeting and faced suspicion from several municipal utilities and cooperatives. (See Munis Wary of PJM Rules on Non-Retail BTM Generation.) Stakeholders at last week’s meeting requested more firm data surrounding megawatt estimates before moving forward in the process.
Committee Endorses Updates to TO/TOP Matrix
Stakeholders unanimously endorsed changes to the Transmission Owners/Transmission Operator Matrix to document their responsibilities under new NERC reliability standards.
The matrix is an index between the PJM manuals and NERC reliability standards that spells out which responsibilities are PJM’s as the TOP and which are assigned to member TOs.
Version 13 of the matrix adds references for reliability standards:
TOP-001-4 R20 and R21, which took effect in July 2018;
VAR-001-5, which took effect Jan. 1;
EOP-004-4, EOP-005-3 and EOP-008-2, which take effect April 1; and
PER-003-2, which takes effect July 1.
The endorsed changes head to the Transmission Owners Agreement Administrative Committee for approval.
Incremental RFP Window for New Black Start Resources Closes May 1
PJM opened a window for new black start resources in the Baltimore Gas and Electric and Potomac Electric Power Co. (PEPCO) zones on Feb. 1.
PJM initiated the new request for proposals — separate from the five-year process completed in November 2018 — after receiving notice late last year of generator deactivations in BG&E’s territory not included in the original scope of projects. The RFP seeks service beginning by April 1, 2021.
“We have included the PEPCO zone and also some surrounding adjacent TO zones in this RFP in the event there are cross-zonal black start options that may be considered,” said David Schweizer, PJM’s manager of power system coordination. “We did not specify megawatts in the RFP because we want to be able to consider any size black start unit that’s proposed.”
Expressions of interest are due by Feb. 25, with detailed proposals due May 1.
Lisle RAS Scheduled for Retirement
A reinforcement project will trigger the retirement of two remedial action schemes designed to prevent thermal overloads at the Commonwealth Edison’s Lisle substation.
The project will add breakers to the four existing 345-kV lines and reconfigure the 345-kV bus into a ring-bus. ComEd said the schemes will be removed as they become unnecessary. The work is scheduled to begin in March and be complete by June 1, 2020.
WASHINGTON — Having regained control of the House of Representatives after eight years in the minority, Democrats have put a lot on their plate, including investigating President Trump’s finances and Russian interference in the 2016 presidential election.
But last week, House Democrats added climate change to their agenda, with two committees holding hearings on the topic simultaneously Wednesday, and Rep. Alexandria Ocasio-Cortez (N.Y.) and Sen. Ed Markey (Mass.) introducing the “Green New Deal” on Thursday.
The hearings came the same day that NASA’s Goddard Institute for Space Studies and the National Oceanic and Atmospheric Administration reported that 2018 was the fourth hottest year on record, with the average global surface temperature for the year coming in only behind those of the previous three.
Since the 1880s, the average temperature has risen about 1 degree Celsius (1.8 degrees Fahrenheit), according to climate scientists. A report released in October by the U.N.’s Intergovernmental Panel on Climate Change said that catastrophic effects from climate change could occur as soon as 2040, when warming is expected to reach 1.5 C if the current rate continues. International efforts, such as the 2015 Paris Agreement, have so far focused on preventing only a 2-degree C increase. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
The IPCC report said the impacts of climate change are already being felt in increased storm intensity, precipitation, wildfires and heat waves; rising sea levels from melting polar ice; and the nearing extinction of several species, including coral.
It was these effects that the hearings by the House Natural Resources Committee and the Energy and Commerce Committee, and their witnesses, focused on during Wednesday’s hearings.
“Our communities are paying the price for years of inaction on this issue,” said Rep. Raul Grijalva (D-Ariz.), chair of the Natural Resources Committee. “The massive and unprecedented storms, heat waves, fires and droughts we are experiencing are not normal. They are being made worse by climate change, and if we don’t take action now, we’re only at the beginning.”
Climate change “goes by many different names: Sandy, Harvey, Maria, Katrina, Camp Fire,” said Rep. Paul Tonko (D-N.Y.), chair of the E&C Committee’s newly renamed Subcommittee on Environment and Climate Change.
Many of the Democratic committee members used their allotted time to talk about the natural disasters unique to their states; Californians especially focused on the wildfires of the past few years.
Similarly, North Carolina Gov. Roy Cooper (D) and Massachusetts Gov. Charlie Baker (R) told the Natural Resources Committee about the challenges their states have faced.
“We’ve weathered two so-called 500-year floods in two years and three in fewer than 20 years,” Cooper said. “In the Western North Carolina mountains, volatile weather has caused mudslides, damaged infrastructure, cost apple growers valuable crops and forced ski areas to close mid-season, hurting local businesses and putting jobs in jeopardy.”
“Shortly after taking office in January of 2015, the snow started falling, hard, and it didn’t end until well into April,” Baker said. “What was different about those storms was the sheer volume of snowfall, with record-breaking amounts in Worcester and Boston.”
Most of the Natural Resources Committee’s witnesses after the governors were environmental and social activists, who spoke of how climate change would hit poor and minority communities the hardest.
“As a poor and working-class community, housing displacement and disruption of services due to storms and other severe weather affect our people much more acutely compared to resident of affluent communities with more resources,” said Elizabeth Yeampierre, executive director of UPROSE, an organization representing the Latino community in Brooklyn’s Sunset Park neighborhood.
Only two scientists appeared on the panel, one of whom, Judith Curry, was invited by Republicans and downplayed the severity of the threat. “Both the problem and its solution have been vastly oversimplified,” said Curry, president of the Climate Forecast Applications Network and former chair of the School of Earth and Atmospheric Sciences at the Georgia Institute of Technology.
Republicans Resistant
Some Republicans at the hearings questioned the science of climate change, asking questions such as whether this was the hottest the planet has been, or whether extreme heat or extreme cold kills more people.
One GOP member of the Natural Resources Committee, Louis Gohmert (Texas), asked Curry, “Do you think we’re causing the polar ice caps on Mars to melt? … That’s probably the sun.”
The Republicans that did not question the science criticized the economic costs and job losses associated with closing down fossil fuel plants, said renewable resources are less reliable than baseload plants and rejected proposed solutions as infeasible.
“We want a healthy environment for our children, grandchildren and their children,” said Rep. Greg Walden (R-Ore.), ranking member of the E&C Committee. “But we also want the people who live in our districts and in this country today, right now, to have jobs and to be able to provide for their families. These are not mutually exclusive principles. Working together, we can develop the public policies to achieve these goals.”
Rep. Rob Bishop (R-Utah), ranking member of the Natural Resources Committee, criticized Grijalva for even holding a hearing on climate change, saying it wasn’t in the committee’s jurisdiction. Instead, he said he wanted the committee to focus on issues such as wildfire management and National Parks maintenance.
“Are these hearings simply for those of us around the horseshoe who are going to be making legislation, or are these hearings simply for those who sit around that table in the corner so they can write cute stories?” Bishop asked, pointing to the table of reporters seated next to the witness table.
He noted that Grijalva had dubbed February “climate change month.”
“I appreciate the fact you picked the shortest month of the year to do that,” Bishop said.
Ironically, between the two governors at the hearing, Baker received most of the Republicans’ criticism. Rep. Tom McClintock (R-Calif.) cited the failure of two wind turbines in Falmouth, Mass. The town spent about $10 million to build the turbines in 2009 and 2011. Last month, the town’s Board of Selectmen voted to shut down the turbines and potentially spend millions more dismantling them after residents continually complained of noise.
Baker responded by saying, “My father always used to say that there’s two things: There’s doing the right thing, and then there’s doing the thing right. And doing the right thing but doing it wrong doesn’t necessarily solve the problem. There were a whole series of issues with a well-intended effort in Falmouth that in many respects failed because they didn’t make a lot of the decisions with respect to where they sited them and how they sited them that would have made sense. …
“I think sometimes when something doesn’t go the way it should go, everybody blames the concept. Well sometimes we actually just screw up the way we implement it, and it makes the concept looks bad.”
Rep. Garret Graves (R-La.) noted that his state was one of the top oil and gas producers in the country, while Massachusetts was one of the top oil and gas consumers. “How do you reconcile what you’re able to do based on your economy versus the challenges in Louisiana based on what our economy is founded on?” he asked Baker.
The governor began to explain how despite productivity and population growth, the state has reduced its emissions. Graves interrupted him, saying, “I do appreciate that you all have taken steps, I do. But I also think it’s important to recognize that states in some cases are fundamentally different.” He pointed out that Massachusetts’ electricity prices are among the highest in the U.S.
Green New Deal
Republicans at the hearings also criticized the so-called “Green New Deal,” a set of goals floated by the progressive wing of the Democratic Party after last year’s midterm elections.
On Thursday, Rep. Ocasio-Cortez, with 60 co-sponsors, formally introduced the idea in the House as a nonbinding resolution, with Sen. Markey introducing an identical resolution in the Senate.
The 14-page document calls for “a 10-year national mobilization… to achieve net-zero greenhouse gas emissions.”
The resolution also contains a hodge-podge of goals, including achieving “maximum energy efficiency” from all existing buildings and “spurring massive growth in clean manufacturing in the United States and removing pollution and greenhouse gas emissions from manufacturing and industry.”
“A new national, social, industrial and economic mobilization on a scale not seen since World War II and the New Deal era is a historic opportunity to create millions of good, high-wage jobs in the United States; to provide unprecedented levels of prosperity and economic security for all people of the United States; and to counteract systemic injustices,” the resolution says.
Specific policy proposals to achieve these goals, however, are absent from the document. And with Republicans still in control of the Senate and the White House, any legislation attempting to codify them is almost guaranteed to fail for the next two years.
Rather, many analysts last week saw the document — and the focus on climate change among Democrats this month in general — as more of a political rallying cry for the party ahead of the 2020 elections.
“It actually will be impossible to enact a Green New Deal while Trump is in the White House, but the resolution still has two useful purposes,” Michael Grunwald wrote in Politico Magazine last week. “It’s primarily a political manifesto, a messaging device designed to commit the Democratic Party to treating the climate crisis like a real crisis, pressuring its presidential candidates to support radical transformation of the fossil-fueled economy. At the same time, the Green New Deal is a policy proposal — or at least a sketch of one, a way to launch a substantive debate over how Democrats will attack the crisis if they do regain the White House.”
“In an increasingly social-media-driven political culture, the bill’s sponsors may be looking to generate ‘likes’ … rather than votes,” ClearView Energy Partners said.
Several major contenders to be the Democratic nominee in the 2020 presidential election endorsed the Green New Deal last week.
Republicans predictably lambasted the document.
“It’s a socialist manifesto that lays out a laundry list of government giveaways, including guaranteed food, housing, college, and economic security even for those who refuse to work,” Sen. John Barrasso (R-Wyo.), chairman of the Environment and Public Works Committee, said in a statement. “As Democrats take a hard left turn, this radical proposal would take our growing economy off the cliff and our nation into bankruptcy. It’s the first step down a dark path to socialism.”
