SPP’s Exit Study Task Force, formed to provide technical support and advice regarding Lubbock Power & Light’s move to ERCOT, conducted its first meeting last week.
The Public Utility Commission of Texas asked SPP and ERCOT to work together to study the implications of LP&L’s plans to migrate 430 MW of its load from SPP to ERCOT in June 2019. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
One issue is who will pay for the studies. PUC Chair Donna Nelson has said the burden shouldn’t fall on ERCOT ratepayers, suggesting during a Sept. 22 meeting LP&L should either fund the work or that the issue should be open “pending the outcome of the studies.”
“‘Depending on the outcome’ … I don’t know what that means,” said LP&L legal counsel Chris Brewster during the task force’s first meeting Friday.
Oklahoma Gas & Electric’s Jake Langthorn, the group’s chair, told the group the study costs will become clear once the scope and schedule are developed. SPP staff will begin its assessment by using its normal base cases from its near-term and 10-year studies.
“We’ll evaluate the system with Lubbock in SPP and without. In each case, we’ll evaluate the system against SPP planning criteria and NERC criteria to see whether we’re outside the acceptable ranges,” said Antoine Lucas, SPP’s director of transmission planning. He said the study will seek to identify any new transmission projects needed — or planned projects that can be deferred — as a result of Lubbock’s move.
LP&L representatives pushed SPP, which has targeted an April completion date, to accelerate its timeline.
ERCOT has said it will complete its assessment by the end of the year.
SPP says its existing planning workload will keep it from completing its work by the end of the year as ERCOT has promised.
“Having said that, we’re expecting it’s more than 90% in place right now,” said Lanny Nickell, SPP’s engineering vice president. “Once we put the schedule together, we can identify when we need it 100% finalized.”
SPP staff said it is meeting with ERCOT staff next week to review all questions posed by LP&L.
The task force is composed of four members of the Strategic Planning Committee and two each from the Transmission and Economic Studies working groups.
Wind, Coal Generation Continue to Rise, Fall
| SPP Market Monitoring Unit
Wind energy continues to rise in the SPP footprint and coal-fired generation continues to drop, according to the Market Monitoring Unit’s State of the Market report for this past summer.
The MMU said wind generation accounted for more than 12% of all energy produced in 2016, compared with 10% in 2015 and 9% in 2014. At the same time, coal generation’s share dropped to 51%, down from 62% in 2014.
Natural gas prices rose from this spring’s record low levels, the MMU said. The average price at the Panhandle Hub was $2.51/MMBtu this summer, compared with $2.60/MMBtu in 2015 and $4.00/MMBtu in 2014.
| SPP Market Monitoring Unit
The “wind alley” of the Texas panhandle, western Oklahoma and western Kansas continues to experience most of the SPP footprint’s congestion. However, the MMU said, congestion has increased in southeast Kansas and parts of Arkansas, which it attributed to higher summer loads and planned generation and transmission outages.
Staff will review the submittals and share them at their next Interregional Planning Stakeholder Advisory Committee meeting.
SPP staff said a joint model is being developed, but it will likely have differences with each RTO’s regional models, and that some of the identified regional needs may not show up in the model.
Separately, SPP and Associated Electric Cooperative Inc. have developed models and assessed the needs for the target areas, posting them to allow stakeholders to submit solutions. The two organizations requested input be submitted by Nov. 7.
SPP Interregional Coordinator Adam Bell told the committee the Northeast Oklahoma target area will no longer be evaluated in the SPP-AECI joint study because of a change of power suppliers in the region. He said the change “resulted in there no longer being potential needs observed on both sides of the SPP-AECI seam.”
VALLEY FORGE, Pa. — After months of debate on proposed definitions for operating parameters, PJM and the Independent Market Monitor rankled some Market Implementation Committee members last week by introducing an unexpected, last-minute compromise package that included one key change but largely maintained the status quo.
The proposal leaves many of the definitions untouched, except for minimum runtime and soak time. The endorsed definition of minimum runtime replaces a unit’s “breaker closure” with simply when a unit is “dispatchable” as the starting point. It also “un-nests” soak time from minimum runtime, differentiating it as its own parameter.
“We think it’s a big step forward,” Monitor Joe Bowring said.
Several stakeholders said they wouldn’t have enough time to give the proposal a reasonable review that day, but a seconded motion to vote on the issue forced them to act. The vote, which was planned for the morning session, was delayed until the afternoon to provide extra time.
| PJM
It was enough: The joint package received support from 75% of stakeholders — far exceeding competing proposals. It also won more than 60% support in a head-to-head vote against the status quo, meaning it will be forwarded to the Markets and Reliability Committee. (See “Members Hear First Read on Plan to ‘Un-Nest’ Operating Parameters,” PJM Market Implementation Committee Briefs.)
The last-minute proposal by PJM and the Monitor caused several stakeholders to question the functionality of the stakeholder process. “Do we just not care about the stakeholder process anymore?” Ed Tatum of American Municipal Power asked during the initial discussion. “What’s the idea of bringing something that no one’s been able to look at?”
After the vote, PJM’s Dave Anders thanked the members “for working through the issue.” He acknowledged their frustration, but he said this was an example of “the stakeholder process actually working.”
He invited members who have thoughts on reforming the process to attend the Stakeholder Process Forum Oct. 24.
Stakeholders Debate ARR Changes
In response to a problem statement approved earlier this year, PJM has begun revisiting its procedures for allocating residual auction revenue rights and hopes to file a solution with FERC on Dec. 31.
Exelon and Direct Energy issued a proposal last week for reducing potential revenue fluctuations under the current allocation. Their proposal would eliminate any residual ARR paths that could receive negative values based on monthly financial transmission rights clearing prices. PJM would then rerun the simultaneous feasibility test before allocating residual ARR megawatts for the month.
PJM’s proposal would give stakeholders the opportunity to opt out of allocations on a path-by-path basis. Sharon Midgley of Exelon said both proposals solve the issue but differ on the approach taken to address the current forced allocation of negative paths to customers. The Exelon/Direct Energy package puts an additional administrative requirement on PJM, while the RTO’s proposal places new analytical requirements on load-serving entities.
PJM’s Asanga Perera explained that the stakeholder proposal puts a heavy burden on PJM staff to process the data for negative pathways within a few days to have the results back to stakeholders in time for the next round of ARRs. He said it creates the potential for PJM to miss a deadline and leave stakeholders without the information necessary to identify negative pathways.
He pointed out that the process for stakeholders under PJM’s plan uses what they already do for the annual ARR process.
However, several stakeholders criticized PJM’s plan, saying their companies don’t have the staff to analyze the thousands of potential pathways each month. “I think PJM’s proposal with the burden placed on the stakeholders, that would be too overwhelming,” said a stakeholder who asked not to be identified. “It would give an advantage to the stakeholders that have the staff and the resources available to do that.”
PJM Looks to Revise Shortage Pricing Procedures
PJM’s Adam Keech presented a shortage pricing proposal to avoid potential volatility posed by implementation of FERC Order 825 (RM15-24).
Under the order’s transient shortage pricing rules, even brief shortages will trigger the maximum penalty factor, which could cause volatility as market participants attempt to respond. (See FERC Issues 1st RTO Price Formation Reforms.)
PJM’s proposal would create steps below the maximum penalty factor based on historical performance so that the maximum penalty does not apply until the reserve is down to the largest single resource’s actual output as opposed to its economic maximum. The measurement would change every five minutes.
Keech noted that in the past 21 months, PJM has observed 845 instances where, under the rules in Order 825, reserve prices would have hit the maximum $850/MWh penalty factor in the Mid-Atlantic and Dominion regions. He hadn’t analyzed the data enough to explain why 759 of them were in 2015 compared with 86 in 2016.
Stakeholders endorsed by acclamation changes to PJM’s credit policy. The revisions to Attachment Q of the Tariff reorganize provisions and make five minor changes to them, none of which affect credit requirements, according to PJM’s Harold Loomis.
The changes also specify that collateral may not be encumbered or restricted and provide PJM “reasonable time” to investigate breaches of credit requirements before implementing remedies, ensuring the RTO’s action is not foreclosed if it does not act immediately.
The revised attachment also replaces a section on peak market activity (PMA) collateral requirements with one specifying PMA credit requirements.
‘Working Groups’ Removed from MIC Charter
Stakeholders endorsed edits to the MIC charter that removed references to “working groups,” as they no longer exist. Working groups were eliminated as part of a larger reorganization of the stakeholder process starting in 2009 that standardized the purposes for and creation of task forces and subcommittees.
Stakeholders Develop Interest List for Black Start Requirements
PJM is soliciting stakeholder feedback on the priorities that should be considered in developing annual revenue requirements for new black start units. The current interest identification includes 13 concerns, including that the Monitor calculate revenue within six months of units entering black start service.
Bowring said the calculations can’t be made without explicit documentation to support “every penny of requested revenue changes” and that documentation must be submitted in a timely fashion. Members asked Bowring to specify what documentation is required.
FERC has been ordered to pay attorney’s fees for stonewalling an energy trading company’s request for documents under the Freedom of Information Act.
Bates | District Court of DC
While the award — $60,168 — was not huge, the fact that a U.S. District Court judge ruled against FERC was unusual.
Kevin and Rich Gates, acting as principals of the energy trading company STS Energy Partners, filed FOIA requests seeking documents related to investigations by FERC’s Office of Enforcement into two other energy trading companies, Oceanside Energy and Black Oak Energy.
The Gates brothers, who have been involved in a very public battle with FERC over market manipulation allegations against one of their other companies, Powhatan Energy Fund, said in filings that they wanted the documents “to shine light on FERC’s recent and punitive efforts against small power market traders for engaging in legal and ubiquitous activity.” They have accused FERC of withholding information before. (See Gates, Powhatan Say FERC Enforcers Didn’t Share Crucial Info.)
FERC eventually produced the information STS had asked for, but the two sides couldn’t agree on the attorney’s fees issue, and it was argued in D.C. District Court.
In his Oct. 5 ruling, Judge John D. Bates noted that the award of legal fees can serve two purposes: encouraging FOIA suits that benefit the public, and compensating plaintiffs for “enduring an agency’s unreasonable obduracy in refusing to comply” with FOIA requirements.
Bates noted that “FERC did show some recalcitrance and at least ‘appeared’ to ‘withhold’ the segregable portions of requested documents merely to avoid embarrassment or frustrate the requester.”
The commission initially issued “blanket denials” for the 41 documents related to the Oceanside investigation and the 294 records identified in the Black Oak case, Bates noted.
FERC released several documents after STS filed suit over the denial, and it released all or parts of 115 documents after the court denied the agency’s summary judgment motion. The commission reached a settlement with the company over the remaining documents in May 2015.
Bates said the agency’s contention that the requested information could not be culled out, or “segregated,” was not a “reasonable basis in law.”
“Nor can FERC prevail on the reasonable basis factor by deciding to release the documents only after forcing the requester to sue,” he wrote.
The brothers have asked the U.S. District Court for the Eastern District of Virginia to allow it to defend itself against FERC’s allegations in a jury trial (3:15-CV-00452-MHL).
VALLEY FORGE, Pa. — PJM has found a way to provide generators with the performance assessment hour alerts that owners requested, but it’s not going to be easy.
The problem is how to get the PAH alerts from PJM’s emergency procedures channel to the Inter-Control Center Communication Protocol (ICCP) and Distributed Network Protocol channels that unit operators say they monitor with far more frequency. The process would translate the emergency procedure signal into a yes or no signal for each resource.
“We can do it. It’s not the prettiest thing,” PJM’s Rebecca Stadelmeyer told the Operating Committee last week. “This is not an easy plug and play. This is a lot of systems actually talking together, even though it sounds like it’s just a simple output. To get there is going to take us some time and some money.”
The minimum estimate of eight months and $150,000 is expected to increase as outside vendors are contracted and PJM staff are redeployed from other major projects, she said. The cost of the changes means that other projects that were already planned may be delayed.
There may be additional costs for generators to make updates to properly receive the signals.
Brock Ondayko of American Electric Power pointed out that PJM has had since at least April to integrate this request into its budgets and avoid any interference with other projects. (See “PJM Considering Notification of Performance Assessment Hours,” PJM Markets & Reliability and Members Committees Briefs.)
“Maybe there needs to be a better mechanism to describe things that stakeholders are asking for to be considered in the budget for the following year,” he said.
All generating units above 100 MW have ICCP access to receive the upgraded signals, PJM confirmed. Those without the feeds will only be able to receive PAH alerts through the emergency procedures channel.
The RTO must map every resource to each region, transmission owner zone and sub-zone. Stadelmeyer warned that units won’t be excused from nonperformance penalties that arise from incorrect mapping or “broken signals” stemming from owners’ failure to make changes needed to receive the signals.
PJM’s request for feedback on whether to move forward with the plan failed to muster much enthusiasm, even with committee chair Mike Bryson twice stepping in to solicit comments. Finally, Sharon Midgley of Exelon said her company is “very much interested” in the project being completed despite the complications. Jim Benchek of FirstEnergy also offered support, but he cautioned that “the devil’s in the details” on the project’s cost-benefit ratio.
The development of the project will likely be tracked through PJM’s new Tech Change Forum, Bryson said.
Jorge Bermudez has resigned from one of five unaffiliated positions on ERCOT’s Board of Directors after his recent marriage triggered a conflict of interest.
Bermudez’s wife is an officer with an ERCOT market participant affiliate, Citibank. The affiliate is not directly involved in the ERCOT market, but the ISO’s bylaws outline a number of stringent requirements for unaffiliated directors. ERCOT said its legal department determined the relationship to be a conflict “based on those requirements.”
“We have no reason to believe at this time that this conflict resulted in any inappropriate actions during his service to the board,” ERCOT spokesperson Robbie Searcy said. The ISO’s board Tuesday will vote again on any matters that Bermudez participated in during its August meeting “to ensure all board actions of record are consistent with these bylaws,” she said.
“For some odd reason, he chose his wife over ERCOT,” joked Texas Public Utility Commissioner Ken Anderson during the commission’s open meeting Oct. 7.
Anderson and his fellow commissioners closed the meeting by heaping praise on Bermudez. The PUC has regulatory oversight of ERCOT and approved Bermudez’s selection to the board in September 2010.
“He’s such a tremendous gentleman, but what are you going to do with kids today? They run off and fall in love,” Commissioner Brandy Marty Marquez said. “It’s sad to lose him.”
In a statement, ERCOT CEO Bill Magness said Bermudez’s “expertise and careful deliberation, particularly regarding financial matters, will be missed greatly.”
Under ERCOT’s bylaws, the board’s Nominating Committee will select and vote on his replacement, retaining an executive search firm to begin the candidate selection process. The candidate must be approved by both the ISO’s membership and the PUC, with the latter’s approval coming “within a time frame that will … avoid or minimize the length of unaffiliated director vacancies on the board.”
Candidates must have experience in one or more of the fields of: senior corporate leadership; professional disciplines of finance, accounting, engineering or law; regulation of utilities; risk management; and information technology. Candidates must be independent of any ERCOT market participants.
Bermudez had 33 years of experience with Citigroup, retiring in 2008 as chief risk officer. He is currently CEO of the Byebrook Group , a research and advisory firm in the financial services industry.
336 MW of Wind and Solar Added in September
An additional 336 MW of wind and solar began operating in September, according to ERCOT’s latest generator interconnection status report. The new additions were:
Duke Energy Renewables’ 110-MW Los Vientos wind farm in South Texas;
Invenergy Wind’s 120-MW Gunsight Mountain Wind Farm in West Texas; and
OCI Solar Power’s 106-MW facility, contracted to San Antonio’s CPS Energy, north of Abilene in West Texas
The ISO now has 25,254 MW of wind capacity and 9,391 MW of solar power operating, under study or with signed interconnection agreements.
The additional capacity helped ERCOT set new demand records for October with peaks of 59,359 MW and 59,909 MW, respectively, during the late-afternoon hours of Oct. 5. The Texas grid operator’s final Seasonal Assessment of Resource Adequacy for October and November had projected a peak demand of 54,400 MW this fall.
VALLEY FORGE, Pa. — PJM is considering a significant increase in the performance participation threshold for participants in its regulation market.
The current minimum participation threshold of 40% may be increased to 75%, RTO officials told the Operating Committee meeting last week. Each unit is evaluated for participation based on its average scoring over the past 100 hours of regulation service on three components: precision, accuracy and delay.
| PJM
American Electric Power’s Brock Ondayko said increasing the participation thresholds could have a major impact on the number of megawatts available to respond, noting that steam units, which make up the vast majority of RegA participants, average a 75% performance score.
As part of a quarterly report on regulation performance, PJM’s Eric Hsia provided a graph of participants’ average performance and frequency of participation. The results provided a stark contrast between participation in RegD — a dynamic regulation signal meant to stabilize constant frequency deviations — and RegA, a signal that is sent every four seconds.
Regulation-capable units that accept the offered price for participation are expected to align their output with the signals they receive from PJM. The RTO’s data show that, while there is far more participation in RegA, participants in RegD participate far more often.
Responses Hard to Predict
PJM said it is seeing wide variability in primary frequency response between evaluated frequency events, with many generators either not responding, withdrawing responses or responding in the opposite direction — decreasing output, for example, when frequency declines. Additionally, a “significant portion” of primary frequency response is coming from load, which can’t be predicted or controlled, PJM’s Danielle Croop said.
It’s a “roll of the dice” every time to see what’s going to happen, she said. Croop presented several graphs of units’ responses to recent frequency response events that showed the units either not responding, stopping their response, not providing sustained response or responding in the opposite direction.
One potential cause of the erratic performance is that a unit’s “operating control mode” is following some other indicator and not in droop mode allowing them to respond to frequency deviations, she said. Units that don’t respond at all might be operating in modes or with governor settings, that don’t allow for response — or have their governors turned off altogether, she added.
About 69% of frequency response in 2016 has come from coal-fired units, Croop said. In response to a question from Ondayko, she speculated that the participation level of natural-gas-fired units at just 19% was likely due to three factors:
Units must be on the grid to provide frequency regulation, so fast-response natural gas units that run sporadically often won’t have an opportunity to get involved;
Control systems might be “squelching” or preventing the response; or
Units might be operating so close to their maximum capacity that they don’t have much room to adjust.
Units that are providing regulation are not expected to also provide primary frequency response, Croop said, and so aren’t calculated into PJM’s expected performance.
FERC last week rejected MISO’s plan for ensuring it terminates reactive power payments when generating units are no longer capable of providing the service or are transferred out of a fleet. FERC said MISO’s proposed method wasn’t “timely” enough, ordering the RTO to make another compliance filing within 60 days (ER 16-2187 and EL 16-61).
MISO contended its approach was similar to one the commission approved for PJM, which requires a generation owner to either file a revenue requirement adjustment or make an informational filing with FERC. (See FERC OKs PJM Revisions on Reactive Power Payments.)
However, while generation retirement and suspension notices are public and made 90 days in advance in PJM, MISO proposed a “generation owner make its filing on or before the date of the change in status for a generation resource.”
FERC also said MISO’s proposed effective date “on the first day of the month immediately following acceptance of the revenue requirement by the commission” fails to guarantee that the termination date and the last day of revenue requirement align. MISO submitted the Tariff revisions to comply with FERC’s June order to show cause that it was not continuing to pay resource owners with deactivated units for reactive service.
In a related order, FERC last week set for hearing and settlement proceedings Illinois Power Generating Co.’s proposal to reduce the reactive power compensation for its coal-fired plant Newton Power Station in southeastern Illinois from $1.6 million to about $821,000 effective Sept. 15, 2016, when the plant’s Unit 2 was scheduled to deactivate (ER16-2422 and EL 16-119).
FERC said further decreases could be warranted because the company, a unit of Dynegy, did not provide capability reports or cost information on the remaining equipment that will continue to provide reactive service at the plant. Dynegy announced the shutdown in May.
Colorado-based environmental group Western Resource Advocates was an early proponent of CAISO’s Energy Imbalance Market and is actively supporting the ISO’s effort to transform itself into an RTO serving the broader West.
Gardner | Western Resource Advocates
RTO Insider spoke with senior policy advisor Nancy Kelly and staff attorney Jennifer Gardner — both based in the organization’s Utah office — about California’s push for regionalization of the Western grid and its political challenges.
Kelly, an economist, previously worked for Utah’s Office of Consumer Services and followed the regional effort to form a transmission organization in the West prior to the Western Energy Crisis of 2000-2001. She also served on the board of the Western Electricity Coordinating Council from 2002 to 2014.
Gardner, who focuses primarily on clean energy issues, said she is trying to play an active role in the regionalization discussion “to make sure governance is structured fairly for all of the relevant parties that have been involved.”
[Speaking to Kelly] You were once with the Utah consumer advocate, and that agency is currently taking a skeptical view of PacifiCorp joining CAISO. Given your background, how do you weigh consumer issues in your perspective on regionalization?
Kelly: “I think a regional organization and a regional system operator is a necessary tool to reliably operate the resource mix that we’re going to be facing as we transition from our current resource base to a new resource base over the next five to 10 years.
“However, from a consumer perspective, I also believe it’s going to bring down costs, and I think we’re already seeing how it can bring down costs by reliably operating an increasing mix of renewables that have no fuel costs — free wind, free sun — so those resources can get bid in very cheaply.”
[Executive Director of the Utah Office of Consumer Services] Michele Beck has said that she wants PacifiCorp to perform a state-by-state consumer benefits study before it joins CAISO. Would you seek such a study before the utility advances with regionalization?
Kelly: “I think that everyone realizes that PacifiCorp has to be able to make the case [for consumer benefits] in front of each of its six [utility] commissions before it could join as a participating transmission owner. And, yes, I’d think that we’d want to see forecasts of those benefits.
“I think one of the concerns for some in the regulatory community is whether the benefits will grow in the future. They grow as the penetration of renewables grows and as coal plant retirements occur. Some in the regulatory community — and some consumer groups — are concerned that those future benefits may not be realized, and I just don’t think that will be the case. The very drivers that drive those benefits will be increasing in the future rather than going away.”
Given the relative simplicity of joining the EIM compared with creating an expanded RTO, would it make sense to step back from regionalization of the ISO and see what develops as more utilities join the EIM?
Kelly | Western Resource Advocates
Kelly: “Having a regionwide EIM would be a great first step. The additional benefits in moving to an RTO would be further reductions of gas burns, because of the ability to share resources across time zones and across hours in ways that you can’t do with an energy imbalance market. Because [utilities] come into the Energy Imbalance Market with resources that match [their] load, [they’re] only balancing within the hour. By moving to day-ahead, you can reduce the number of resources that need to come into the day beyond the number of resources that come into the hour, so you get greater savings.
“I think the EIM can continue to grow separately from the speed of progress on the regional system operator. As utilities and customers in the West experience those benefits, I think they will become even more willing to do the hard work necessary to take the next step.”
How do you see the West working through the thicket of RTO governance issues, because there seem to be a lot of points of contention both inside and outside California?
Gardner: “We’re really working with a complicated situation. We’ve got six states within PacifiCorp’s footprint with very different politics and policies. I think the biggest issue that we’re finding is … if this seems like a California-driven effort, there’s going to be an expected amount of skepticism. I think that’s normal when you look at all of the policies and political implications at play.
“We’re finding that [California is] going to have to give a little to get something in return. One of the biggest issues that came up in the [governance] process was the issue of voting [in an RTO]. We could all agree that we wanted some kind of advisory body that would provide input to a future independent board, but we couldn’t agree what its voting rights would look like. For example, does California get more votes than Utah because it has a greater load profile?
“Those are the kinds of complicated issues that we’re working through. Ultimately, we want a fair and balanced governance model that recognizes the variety of interests involved in this complicated market structure and that’s ultimately fair to participants — whether it’s a state, a utility or [nongovernmental organization] like us.”
What next steps must be taken to work through the governance issue?
Gardner: “Right now, California needs to pass legislation by the end of 2017. That legislation needs to be clear that CAISO has the legal authority to actually transition to a regional system operator with a fully independent regional board that is advised by a Western states committee of state representatives — and that also has some type of formal stakeholder process. Once we have that legislation in place — then and only then — can we start a transition process that’s necessary to transform CAISO into a regional organization.”
Do you think there’s a willingness on the part of the California legislature to give up enough in the next year?
Gardner: “I can’t say for sure what the temperature of the California legislature is. I think some of the biggest concerns in California primarily focus on making sure that, under a regional expansion model, California isn’t losing clean energy jobs to other states in the West.
“Do I think that’s a fair characterization of what we’re trying to do? No. But when you look at where they’re coming from, this is a California entity, and for the life of that entity, it is charged with implementing — arguably — California policy. So what has to happen is a little bit of letting go and realizing that California can still have its policies and its individual state requirements — and so can Utah. But, ultimately, operation of that regional market must take place by an independent entity. Once we get over those concerns, I think we can make progress, but it’s going to be a heavy lift.”
Kelly: “Within California, there are certainly different interests. What seems to be clear is that CAISO understands that it needs the expansion in order to operate the level of renewables that are coming down the pike — effectively and at lower costs while maintaining reliability.
“I think that CAISO — maybe more than anyone else in the West — gets that. But I do hear in a lot of conversations skepticism about what’s really driving CAISO, and I do think sometimes they’re seen as expansionist and imperialist.”
What are your thoughts on the Mountain West Transmission Group proposal to create a competing RTO in the West? Does that seem like a serious effort — and one that would be competitive with the ISO?
Kelly: “I think it’s totally serious. Whether it’s competitive or not is unknown. They have put out a request for information to four different RTOs, including the CAISO, SPP, MISO and PJM. So they are looking to either form a single tariff group or [create an RTO] if the numbers come in right. I think they’ve been looking at the results of their benefits studies and they’re waiting for information on their requests for information. If they were to choose CAISO, it wouldn’t be competing at all. It would provide transmission access across the West, which I think would be an excellent thing for renewables and customers in the West.
“We’ll support any efforts to improve operation and reliability going forward. I think we would prefer to see one — as opposed to many — simply because that would create the best opportunities to share back and forth across the region.”
Limon Wind Turbines in Colorado | Western Resource Advocates
Is there any policy point that would cause your organization to withdraw its support from the regionalization effort?
Kelly: “I would say that we definitely support an independent board with an open stakeholder process. I think having the governance right is important for our organization. We would not support an organization run by a board appointed by the governor of California. We understand that would never go in the rest of the West.
“Our desire is to see the formation of an organization that can really meet the needs of the entire West and that’s where we’re focusing our work.”
Gardner: “It would be hard to convince Western Resource Advocates to not support this, but there are a few things that could cause us to step back and re-evaluate how we’re engaging in this effort.
“The first would be what happens in California during the 2017 legislative session. We want to make sure that any legislative package is narrowly focused on the issue at hand — which is to enable the California ISO to actually transition to a regional market — rather than [legislators] trying to slip in a lot of additional initiatives.
“We want to ensure that any governance model is fair to all stakeholders involved, and that states outside California are given an equitable say in governance and a seat at the table.
“So it’s really hard to say right now what will be a deal breaker for us. I would say that, depending on what happens with California legislation, we’ll know a lot more about where things stand and whether this process is going to turn out with an equitable governance structure in the long run. But, so far, we’ve been very encouraged and we’re certainly not stepping back anytime soon.”
Imperial Irrigation District last week approved an agreement to secure an additional 3 MW of renewable energy from the Hoover Dam, bringing the reallocation total up to 10 MW for the next 50 years.
IID will pay an all-in rate of $27 to $29/MWh, compared with its all-in average ranging from $50 to $75/MWh. Delivery will begin Oct. 1, 2017, after the dam’s current contracts expire.
“This is an example of how IID is working to diversify its energy portfolio while, at the same time, investing in low-cost energy resources,” IID Board President Norma Sierra Galindo said. “It serves as an important reminder of the true nexus between water and power.”
State Building Energy Efficiency Program Apparently Stalled
A program established by the General Assembly in 2011 to increase energy efficiency in state buildings may be stalled, according to an Oct. 4 report issued by Acadia Center.
The “Lead by Example” (LBE) program was enacted with the goal of achieving a 20% reduction in energy use in state buildings by 2018. LBE required the Department of Energy and Environmental Protection to develop a plan achieving minimum energy savings targets by certain dates and to submit annual reports to the Energy & Technology Committee of the General Assembly regarding the status of implementation.
According to the Acadia Center, annual LBE status reports for 2013, 2014 and 2015 do not appear to have been submitted.
Branford Expected to Approve Ordinance Banning Fracking Waste
Branford officials are expected to approve on Oct. 12 a proposed ordinance banning fracking waste from being used for any purpose within the town. The proposed ordinance does not affect transport of waste materials through Branford on Interstate 95.
If Branford approves the ordinance, it will be the fifth state municipality to enact such a regulation. The towns of Washington, Coventry, Mansfield and Portland also have banned fracking waste.
New proposed regulations addressing how the state will monitor the movement and usage of fracking waste are due between July 1, 2017, and July 1, 2018, according to the state’s Fracking Waste Moratorium.
City Council Seeks Alternative To Second Transmission Line
The Ketchum City Council is seeking a renewable energy alternative to a second Idaho Power transmission line that is expected to cost ratepayers $30 million. The line was intended to address outages in the northern Wood River Valley if the existing transmission line fails.
The council voted last week to ask the state’s Public Utilities Commission to require Idaho Power to analyze the costs, benefits and reliability of an alternative project.
Members of the Ketchum Energy Advisory Committee “believe the $30 million proposed for the line is not the most efficient use of the funds,” Ketchum Planning Director Micah Austin said at last week’s council meeting.
Alliant Energy has apologized to customers who were surprised by higher-than-normal bills, but stands by their accuracy.
Alliant installed a new software system that increased the number of checks it performs on customers’ monthly usage. When the system found usage that was a lot higher than in previous months, it sent estimated bills to customers.
The company said it has temporarily stopped disconnections for affected customers and that it will help them set up payment plans and waive late-payment fees.
Solar Farm Anticipated for Former Westover Air Base Land
The Chicopee City Council is expected to create a solar field on land outside Westover Air Reserve Base that once held about 128 homes.
Chicopee acquired the land in 2011. Last week, the council was asked to approve a 20- to 25-year lease with Con Edison Development, which was selected through a bidding process to design, construct and maintain a solar farm on the property.
The solar farm is expected to cut the base’s electric bill by 5%, or $100,000 a year.
Pittsfield’s city council will vote Tuesday on whether to spend $562,000 to upgrade Covanta’s waste-to-energy recycling facility to keep it open for at least four more years.
In July, Covanta announced plans to close the Pittsfield facility in March 2017, stating that high operating costs and the size of the plant made it unprofitable.
The money, which would come from Pittsfield’s economic development fund, would pay for a state-mandated recycling enclosure and upgrades to the facility’s fossil fuel boiler.
Hurricane Matthew has dissipated, but it left about 491,000 residents in the state without power in its wake as of Monday morning, according to the Department of Public Safety.
The figure, which includes about 310,000 Duke Energy customers, was as high as 600,000 on Sunday. Duke could not estimate how long it would take to restore service, but the prognosis is not good. “In some of the harder hit areas, we expect to have to rebuild portions of our system before we can restore power, and that takes time,” spokeswoman Meredith Archie said.
Duke has deployed about 5,600 workers to respond to outages and help with clean up, Archie said. Some communities on the state’s coast have been evacuated because of dangerous flooding.
The Development Services Agency is offering up to $8 million to advance research on cleaner, economical and greater use of the state’s coal and/or its combustion products.
The agency expects to issue eight to 10 awards for up to two years of research. Amounts will range from $3.5 million for full-scale projects to $100,000 for paper studies.
Proposals are due by the end of October to the Coal Development Office.
WASHINGTON — FERC’s Order 1000 is providing savings to ratepayers, but a lack of transparency in RTOs’ competitive solicitations is undermining confidence, and limited opportunities may doom nonincumbent developers, speakers told the Energy Bar Association Mid-Year Energy Forum last week.
The range of comments were similar to those FERC heard at its June technical conference on the landmark rule. More than 60 stakeholders filed post-technical conference comments last week before the deadline Oct. 3 (AD16-18). (See Five Years Later, FERC Takes Another Look at Order 1000.)
“We’re out of the policy debates and into implementation,” said Brian Weber, managing director of transmission development for Transource, a joint venture of American Electric Power and Great Plains Energy.
Weber said it is “too early to make broad brush changes” in the rules, given that some RTOs have yet to complete their first Order 1000 solicitations.
Other speakers at the EBA session saw no need to wait to fix problems.
Paul Jett of Midcontinent MCN, GridLiance’s operating company in MISO, said FERC’s policy is sound, but the implementation “is off to a slow start” because the continued existence of state rights of first refusal and RTOs’ reliability project “carve outs” for incumbents have left an “extremely narrow” set of projects open to competition.
George Dawe, vice president of Duke-American Transmission Co., echoed Jett’s complaint, saying incumbent transmission owners weren’t the only ones to oppose competition. RTOs don’t like it, Dawe said, because “they’re in the spot of having to pick winners and losers.”
“So we end up with these design flaws … created in the very beginning because those two entities in particular didn’t want competition in the first place. And so you end up with arbitrary voltage thresholds, cost allocation issues [and] limited benefit metrics to determine which project should be eligible” for competition.
FERC needs to “course correct,” he said, by reassigning the competitive selection job from the RTOs to their Market Monitors.
Dawe and other speakers also said more transparency is needed to increase confidence in the selection process.
Weber said that’s one reason his company likes the sponsorship model used by PJM rather than the practice in CAISO, where the ISO accepts competitive bids on a solution developed by its engineers.
“You propose your solution and if your solution is the best solution it saves the need for all the issues which may come with more of a competitive bid process,” Weber said.
“There are some regions that have issued very subjective criteria — multiple criteria — but really only give one of the criteria that they’ve issued,” he continued. “So that leaves you in a situation at the end where you can’t draw a straight line between the end result and what was communicated up front.”
Weber contended competition should be limited to capital costs, saying the inclusion of operations and maintenance and tax considerations introduces too much subjectivity into the evaluation.
“We’ve been involved in certain regions where … you put everything in an Excel spreadsheet, there’s a multi-hundred-page contract behind it that covers every potential outcome and the decision is made on a single cell in [the] spreadsheet.”
Judy Chang of The Brattle Group said the introduction of competition and cost caps is providing benefits to ratepayers, a conclusion with which other speakers agreed.
“Cost containment and cost caps … look to be the new normal,” Dawe said. “It’s hard to imagine there would be a successful bid that doesn’t include some form of containment.”
Brattle says annual transmission spending has increased since FERC issued Order 1000 in 2011. It predicts $120 billion to $160 billion in transmission investments over the next decade.
But that may not be enough for the growing number of independent transmission developers, Jett said. “If you’re a developer and Order 1000 transmission projects are your only path to success, you’ve got a problem today,” he said.
“If these design issues are not addressed quickly, I have to wonder how long will developers be able to hang on.”
Imperial Irrigation District last week approved an agreement to secure an additional 3 MW of renewable energy from the Hoover Dam, bringing the reallocation total up to 10 MW for the next 50 years.
The Development Services Agency is offering up to $8 million to advance research on cleaner, economical and greater use of the state’s coal and/or its combustion products.
