ERCOT’s latest seasonal assessment of resource adequacy (SARA) indicates ample generation for spring, with more than 82 GW of generation for an expected peak demand of 58 GW.
Nearly 1.5 GW of new gas-fired, wind and solar generation has become operational since the preliminary spring SARA was released in November.
Texas Wind Farm | Target
A preliminary summer SARA anticipates a new record peak of nearly 72.9 GW, with 81.6 GW of capacity. That would break the mark of 71.1 GW set last year on Aug. 11. ERCOT said it expects another 2.5 GW of new gas-fired and 1.6 GW of wind and solar generation to come online before the June-September season begins.
ERCOT Senior Meteorologist Chris Coleman is predicting another hotter-than-normal summer in Texas this year. He said during a media conference call last week that the state is coming off what may be its warmest winter on record, and he does not expect any significant changes in the “warming trend.”
Panda Power’s 758-MW Sherman combined cycle generator in Sherman, Texas, went online in 2014. | Panda Power Funds
“Eight or nine of the past summers have been hotter than normal,” he told the ERCOT Board of Directors in January. “That’s just been the trend. It would really be going out on a limb to forecast a mild summer for Texas this year.”
LAS VEGAS — Increased adoption of behind-the-meter generation is complicating short-term load forecasting across the Western Energy Imbalance Market (EIM), especially in the Arizona Public Service area.
The challenge is caused by the unpredictability of cloud cover, which can cause sharp and sudden drops in solar production.
“In the past, cloud cover was always a variable that came in for load forecasting, but it was really interrelated to temperatures,” Amber Motley, CAISO manager of short-term load forecasting, said during a March 1 meeting of the EIM Governing Body at The Palazzo hotel.
The conventional understanding: Clouds would move over an area, causing temperatures to fall, which would in turn reduce system load.
“Now, when you get high penetration levels of rooftop solar, there is a point in time when clouds come over and your [net] load is going to increase instead of decrease” because of reduced output from rooftop solar, Motley said.
A Caveat
Motley offered one caveat to that assessment: When daily temperatures average about 80 degrees Fahrenheit, temperature is still the main driver of the load forecast.
Under those conditions, air-conditioning load still drives enough electricity consumption that a cloud system causing a 10-degree drop in temperatures is going to reduce load.
Further complicating matters is humidity, which causes air conditioners to work harder and support load even under cloud cover. The situation is especially problematic in summer when monsoon moisture is thrown into the mix.
“You really have a question to ask yourself: Is my load going to increase because I am losing the rooftop solar, or is it going to decrease because I have a 10-degree temperature drop?” Motely said. “And we’ve seen both situations happen.”
Motley called APS the “most challenging load-forecasting region” within the EIM.
“It has a combination of a significant amount of rooftop solar, which is a driving factor, combined with some of those strong monsoon days in the summertime,” she said.
APS began transacting in the EIM last October, after the summer solar and monsoon peaks. But CAISO began running EIM load forecasting models ahead of the go-live date, giving operations staff an indication of what to expect this summer.
High Error Rates
So far, even outside the summer months, short-term load forecasts for the APS area are recording relatively high error rates compared with other EIM balancing areas (see chart). In November, the region’s hour-ahead forecast error rates reached nearly 2%, falling to 1.5% the following month. NV Energy has had similarly high error rates in the summer because of the prevalence of dust storms — a phenomenon that affects Arizona as well. The error calculations represent the average deviation between hour-ahead forecasted load and actual load.
The ISO’s goal is to keep error rates below 1%, Motley said, adding that such accuracy is not always attainable in some regions.
Graph shows the hour-ahead load forecast error rates for the EIM balancing areas outside CAISO during 2016. APS errors have outpaced those of other regions since the utility joined last October. | CAISO
“If you have more rooftop solar, your accuracy is going to be worse because you now have another characteristic behind the scene that is influencing it,” Motley said.
She pointed out that short-term load forecasting is an important component for market optimization and reliability. It also is used as a key input for dispatch operation functions such as unit commitment, economic dispatch, fuel scheduling and generation and transmission maintenance.
EIM Governing Body member John Prescott wondered if there was a “nexus” between load forecasting errors and the high number of flexible ramping test failures observed in the EIM late last year — particularly in APS. (See EIM Sees Sharp Increase in Flexible Ramping Test Failures.)
“There are several factors that play into that and we have to isolate each one to see what’s driving it,” said Justin Thompson, director of resource operations and trading at APS. “But load forecast is one piece of it. Also, how well have [we] forecasted wind? … How well [have] we forecast the solar output?”
Phoenix Baseline?
Alyssa Koslow, a regulatory analyst at Salt River Project, said she had heard CAISO was using Phoenix as the baseline for forecasting for Arizona, despite the fact that APS’s territory extends into high-elevation areas.
Motley clarified that the ISO’s approach to forecasting is more comprehensive than that.
“We have multiple temperature stations within Arizona, and [the load forecast] is always driven by the temperature station that’s closest to where your load pattern moves the most,” Motley said. “So we work with all of the EIM entities on which station in which area moves the most for your load and then we incorporate that into the design.”
“One of the problems with models is ‘garbage in, garbage out,’” said Clay MacArthur of Deseret Power. “There’s a lot of behind-the-meter generation going on. How do you aggregate” the capacity?
Motley responded that the ISO takes a bottom-up approach that starts with the zip code and capacity for every interconnection on the distribution system. That information lays the foundations for system load forecasts for individual areas.
“And then we forecast the irradiance — which is essentially the amount of sunlight that’s going to come from the atmosphere to the roof for that resource — and we put that into the forecast as its own variable,” Motley said.
Neural Net
That last point is important for CAISO’s “neural net” forecasting method, which relies on the dynamic interplay between “highly interconnected processing elements” — the data fed into the model. As Motley explained, the neural net is modeled on the human brain and can synthesize copious amounts of information and “learn” to weight the importance of certain factors over others in their predictive processing.
“Storing the information by technology type is very important so that the neural net can have the correct connections,” Motely said. If that information gets “blended in with the rest of the model,” then the neural net has a difficult time distinguishing whether it was a change in temperature or solar output that caused load to move up or down.
CAISO continues to seek ways to improve its load-forecasting model, Motely said. Future improvements could include having EIM participants share their own load forecasts to provide comparisons, as well as having them provide balancing area information about demand response, hydroelectric behavior, rooftop solar and irrigation patterns.
“Can we fix everything? No, it’s forecasting — it’s good job security,” Motley joked. “But are there some things that we can fix? Yes, there are some things.”
CenterPoint Energy said it is continuing to evaluate an offer for its ownership share in Enable Midstream Partners, and it expects to “clarify” its position in the third quarter.
The Texas company has a 55.4% stake in the gas gathering and processing venture with Oklahoma City-based OGE Energy. CenterPoint is considering an offer to purchase its share, but it could also spin off the business or continue to manage its position.
“If we determine that neither a sale nor a spin would fulfill our criteria, our third path will be to maintain our stake in Enable and continue to support efforts to reduce exposure to commodity price influences,” CenterPoint CEO Scott Prochazka said.
OGE made a second offer for CenterPoint’s stake on Feb. 15 under its right of first offer (ROFO), along with an unnamed partner. CenterPoint, which rejected OGE’s first offer in September, has until June 15 to make a final decision.
Prochazka said CenterPoint is continuing its “dialogue with interested parties” and it will “evaluate OGE’s recent offer made pursuant to the ROFO terms of our partnership agreement.”
“While the process is taking longer than originally anticipated, we expect to clarify which path we are on by the second-quarter earnings call,” he said.
Prochazka’s comments came during a Feb. 28 conference call with financial analysts following the company’s fourth-quarter earnings announcement.
Q4 Earnings Fall Short
CenterPoint fell short of analysts’ expectations, reporting fourth-quarter net income of $101 million ($0.23/share), compared to 2015’s fourth-quarter loss of $509 million (-$1.18/share). Zack’s consensus estimate was 29 cents/share.
The 2015 results included impairment charges totaling $984 million from its midstream investments. The company attributed the turnaround to rate increases and customer growth in its electric and gas utility businesses.
For the year, the company reported net income of $432 million ($1/share), compared to 2015’s loss of $692 million ($1.61/share).
CenterPoint reiterated its 2017 guidance of $1.25 to $1.33/share.
The company’s stock gained $1.99/share in the four days after the earnings announcement, ending the week at $27.90. CenterPoint shares have risen more than 13% since the beginning of the year — doubling the 6.4% increase in the Standard & Poor’s 500 index — and are up 43% in the last 12 months.
Executive Appointments
On March 1, the company announced three executive appointments: Scott Doyle as senior vice president of natural gas distribution; Joe Vortherms, as senior vice president of CenterPoint Energy Services; and Jason Ryan, vice president of regulatory and government affairs. Doyle and Vortherms will report to Prochazka. Ryan will report to General Counsel Dana O’Brien.
NYISO CEO Brad Jones and Public Service Commission Chair Audrey Zibelman told New York legislators they are not concerned about replacing the capacity of the 2,069-MW Indian Point nuclear plant, saying energy efficiency, transmission upgrades and the ISO’s wholesale market will ensure reliability.
Jones said that the grid operator has many options and “plenty of time” to resolve any reliability issues arising from closing the plant. In an aside, he also said the ISO is considering requiring new gas-fired generation to have dual-fuel capability.
NYISO has yet to receive a formal notice of deactivation of Indian Point, which would trigger a 90-day assessment period, but Jones told legislators during an eight-hour hearing Feb. 28 that he expects one will be filed in the coming months.
Joint Hearing
The State Assembly’s Committee on Energy held a joint hearing with the State Senate’s Committee on Energy and Telecommunications on the plant, located on the Hudson River 30 miles north of New York City. Plant owner Entergy and Gov. Andrew Cuomo announced an agreement in January to shut down Unit 2 in 2020 and Unit 3 in 2021. Unit 1 ceased operations in 1974. (See Entergy to Shut Down Indian Point by 2021.)
Left to right: Sen. Griffo, Rep. Paulin and Rep. Palmesano | New York State Committee on Energy & Telecommunications
Assembly committee Chair Amy Paulin (D) asked how the ISO evaluates the reliability effect of a facility going offline. Jones said that several factors influence the assessment process, mainly the fast-changing power system itself.
“Literally, the system is changing as much as it ever has in the past,” Jones said. “For example, we have new transmission, some that is under construction, as well as transmission that is in the process.”
He also noted increased energy efficiency and production from rooftop solar panels as well as “load shifting” by some market participants.
Senate Committee Chair Joseph A. Griffo (R) asked Jones whether the state’s goal of having renewables provide 50% of its electricity by 2030 was realistic. Jones said the goal was “ambitious, but achievable.”
Dual-fuel Requirement Coming?
Paulin asked the CEO to pinpoint the possible outcomes of a reliability assessment on Indian Point’s closure. Jones said that in the event of a reliability concern, the ISO would first approach the market to find solutions. If the market failed to find a solution, the next step would be to look for a regulatory fix.
Zibelman and Richard Kauffman, Chairman, Energy and Finance for New York testify before the joint committee | New York State Committee on Energy & Telecommunications
“Now, one of the options for the replacement of Indian Point would be to have additional gas units that come online to replace that,” Jones said. “There are a variety of different scenarios that I think are feasible. If the replacement generation does come from natural gas, we have been concerned at the NYISO, as we rely more upon natural gas, about the reliability of the supply of the gas itself. And so we’ve begun to look at … whether we should and could require generators throughout New York to have a dual-fuel supply.”
Planning Since 2011
Zibelman | New York State Committee on Energy & Telecommunications
Zibelman said the state has been planning for Indian Point’s closure since at least 2011, citing the AC Transmission project, which should begin construction in 2019 and be operational by summer 2022. She said new or mothballed generators will enter the ISO market if needed.
“New York has had a really good history of power plants getting built in response to market” demand, she said, citing the 6,000 MW of new plants added since the NYISO markets began.
“I’m not concerned about the replacement power. We have a robust market. There’s a lot of capital. People are very interested” in building new plants, she continued. “That plus the work we’re doing on energy efficiency and demand response and the transmission — all of those in combination is what makes me extremely comfortable that we’re not going to have a scarcity issue.”
She noted that New York’s wholesale power prices declined by 25% between 2012 and 2016, thanks largely to cheap natural gas. Over the same period, energy efficiency has caused the ISO to reduce its 2021 peak load forecast by almost 7% to 33,555 MW. Thus, she said, the plant’s closure should have a “negligible or no adverse” impact on consumers’ bills.
“Since prevailing wholesale prices are now lower than the cost of existing nuclear generation, it is anticipated that any new replacement power in the long run will be cheaper than continuing to buy power from Indian Point,” she said.
Worries over Economic Impact
Twomey | New York State Committee on Energy & Telecommunications
Also testifying was T. Michael Twomey, vice president of external affairs for Entergy’s wholesale power business, who was questioned about the company’s decommissioning plans and its offer to relocate laid off plant workers.
Much of the hearing was focused on the economic impact of the plant’s closure, primarily the loss of the plant’s property tax revenues and its 1,050 jobs.
On the morning of the hearing, Cuomo announced the formation of a task force to ease the impact on the community. “The task force will partner with local governments to address employment and property tax impacts, develop new economic opportunities” and retrain the work force, the governor’s office said in a news release. “The task force will also monitor compliance with the closure agreement, coordinate ongoing safety inspections and review reliability and environmental concerns, among other issues.”
LAS VEGAS — The West-wide forum created by CAISO to foster discussion about Energy Imbalance Market-related issues outside the ISO’s normal stakeholder process is worth preserving — and developing further.
That was the general consensus of stakeholders and EIM Governing Body members who gathered at The Palazzo hotel last week to discuss the fate of the Regional Issues Forum (RIF), which was established in 2015 as the ISO began to build momentum for “regionalization” — the push to expand into other parts of the West.
“We all value what the RIF has been doing,” Governing Body Chair Christine Schmidt said during a Feb. 28 joint meeting that included fellow body members, RIF representatives, industry participants and interest groups. “We value the promise of what the RIF can do going forward.”
Speaking in her capacity as a Washington state utility commissioner, Ann Rendahl — chair of the EIM’s Body of State Regulators — voiced her support for the RIF as someone “who is coming into this market new and learning a lot.”
“The Regional Issues Forum discussions have been very helpful, because you are all participating in the market and you have experiences that are helpful for us to learn and hear, in addition to the formal stakeholder processes that the ISO puts on,” Rendahl said.
Accolades notwithstanding, uncertainty still looms about the future role for the forum, what formal structure it should assume and how it should interact with the Governing Body.
Doug Howe, the body’s vice chair, referred to it as “the existential question of ‘What’s the RIF?’”
RIF representatives, called “sector liaisons,” have committed to answering that question and developing an operating framework for the group in time for the Governing Body’s July meeting.
“The liaisons don’t see a lot of barriers to getting this done in an expedited way,” said Tony Braun, RIF chair and a liaison representing the publicly owned utilities sector.
Informal Body
The RIF was conceived under the EIM charter as an informal body to enable industry stakeholders and the public to discuss wide-ranging issues related to the West’s only real-time energy market. (See PacifiCorp Offers Lessons for Future EIM Participants.)
The forum is organized by 10 liaisons representing five industry sectors: independent power producers and power marketers; transmission-owning utilities; publicly owned utilities; consumer advocates; and balancing areas neighboring the EIM — the last of which is a diminishing group as the EIM grows, Braun joked. CAISO planned for the RIF to meet about three times a year but required no set schedule.
According to the ISO, “The forum may produce documents or opinions for the benefit of the EIM Governing Body, ISO Board of Governors and the ISO,” but it sits firmly outside established stakeholder processes.
The EIM’s governance documents call for the RIF’s role to be re-evaluated by next month, which was the primary reason for the Feb. 28 joint meeting.
A key question in the re-evaluation: How should the RIF run the process to re-evaluate itself?
“Should this be an ISO-run stakeholder process in the traditional fashion?” asked Braun. “Is this something that the liaisons should take ownership of? What should be the liaisons’ role in putting together the recommendations and things like that, if any?”
Schmidt said she didn’t think the RIF’s evaluation was ever intended to become part of an ISO stakeholder process.
“I think the general consensus [among CAISO and EIM leaders] is that the Regional Issues Forum is the Regional Issues Forum,” Schmidt said. “However the re-evaluation needs to take place, this is in your control and is in your span of control and authority, and you should actually go through that process as a Regional Issues Forum issue.”
Speaking on behalf of her company, RIF liaison Sara Edmonds, general counsel at PacifiCorp Transmission, supported the general independence of the RIF, but she noted that the group has no funds or processes to post material coming out of its meetings.
“We’re happy as the liaisons to kind of be the muscle to pull together the substance [of the re-evaluation], but we’re still going to need the ISO vehicle to get the information out [and] help us with the meetings,” Edmonds said.
Ellen Wolfe of Resero Consulting, representing the Western Power Trading Forum (WPTF), backed Edmonds’ view. The WPTF sees “a lot of value” in the continuation of the RIF and agrees with the bottom-up approach to re-evaluation, she said.
‘Grass-Rootsy’
“We do like the idea of the RIF being very ‘grass-rootsy,’ so to speak, but also appreciate the ISO providing the infrastructure for posting comments and market notices and so forth,” Wolfe said.
Howe sought more clarity on the process the RIF would adopt in its re-evaluation.
“So we know that is not going to be a formal ISO stakeholder process — which means a few things, but among them is that you’re not going to start with an issue paper that’s going to be delivered to you by the staff of the ISO,” Howe said.
“So, to some extent, either you’re going to have to deliver the issue paper, or you’re going to have to take in the comments, perhaps write a strawman proposal, and send that out for another round of comments.”
Howe wondered whether ISO staff would ultimately be charged with writing the strawman based on what RIF liaisons heard during the Feb. 28 meeting.
“In my mind, we’re either fish or fowl,” Braun responded. “So if this is a process that the RIF liaisons are going to take ownership of, then my colleagues as the liaisons need to pick up the pens and craft the issue paper of the first straw proposal.”
“We’re all devoting our time and energy to this because we think it’s important,” said RIF liaison Matt Lecar, principal at Pacific Gas and Electric. “But there is a lack of formal structure, and therefore a lack of funding and resources to do things like write the extensive issue papers and straw proposals that the CAISO staff otherwise would in a CAISO stakeholder process.”
Hands Off
On the question of who should be responsible for approving the RIF’s proposal for a framework, Governing Body members advocated a mostly hands-off position.
“I am not seeking to have authority over what the RIF does,” said Governing Body member Valerie Fong, adding that she wouldn’t want to be cut out of the RIF’s activities because of the forum’s educational value. “I won’t be offended if [RIF members] decide that the EIM Governing Body does not have a decision in this process.”
Howe seconded Fong’s sentiments, saying he didn’t see a role for the Governing Body to put its “blessing” on the RIF’s final proposal.
“The primary purpose of this [process] is to construct an organization that helps you all to be effective, and I just want to thank you for including us in that,” Governing Body member Carl Linvill said. “But as far as any kind of formal approval, I’m with what everybody else has said: I don’t think we need that.”
Fellow body member John Prescott said it was important for the RIF to be transparent.
“What I want is access to the knowledge,” Prescott said.
Schmidt reminded her fellow body members that the RIF is embedded in the EIM’s governing documents, meaning that decisions around the RIF will still be subject to some CAISO oversight.
“If there’s a resource impact, or any other impact on the ISO or the ISO’s Tariff, those are matters that will have to be decided by the EIM’s Governing Body and ultimately the [ISO’s] Board of Governors,” Schmidt said.
RIF as Author?
Another key issue facing the RIF: whether it will produce papers on issues coming before the EIM Governing Body.
Stacey Crowley, CAISO vice president for regional and federal affairs, affirmed that ISO staff would be willing to take down comments from a RIF meeting.
“We’re happy to help,” Crowley said, adding that it would be up to the RIF, however, to craft substantive policy recommendations.
Howe emphasized the need for the RIF to document the views arising within its discussions. “If you don’t turn this into a written product, these are conversations that get lost in the dark,” he said.
Jennifer Gardner, staff attorney with Western Resource Advocates, asked whether the RIF could play the role of flagging issues for the Governing Body that are not already being addressed in CAISO’s stakeholder process.
“Is there value, from the Governing Body’s perspective, in having something a little bit more formalized with the RIF?” Gardner asked. A more formal process would entail producing written comments, rather than just “casual dialogue” among RIF participants.
“Does the RIF have to come to consensus on everything?” Fong asked. “Does it have to be giving us an overall perspective from a RIF level? I’d say ‘no.’ I’m OK with the individual input” from RIF participants.
Howe agreed with his colleague and added his own perspective.
“For me, the value is the eyes and ears out in the field to flag issues which may not have risen to the level [of] the ISO yet,” Howe said. “What doesn’t have value for me would be for the RIF to try to turn itself into a formal stakeholder process, because we’ve already got that [within the ISO]. And that just wouldn’t provide additional value.”
VALLEY FORGE, Pa. — And the winner is … LS Power, again.
Warren Beatty wasn’t on hand, but PJM still received plenty of criticism Friday after planners reaffirmed — with some scoping changes — their previous selection of LS Power’s proposal for the contentious and long-awaited reliability upgrades on Artificial Island.
The island on the southwestern edge of New Jersey is home to three nuclear reactors owned by Public Service Enterprise Group, which have been forced to operate for years below capacity and in accordance with a complex operating guide.
Salem and Hope Creek Nuclear Generating Stations on Artificial Island
Last August, PJM’s Board of Managers suspended the project for additional review after PSEG raised a series of engineering concerns and increased the cost estimate for its portion of the upgrades by at least $135 million. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
Scope, Costs Reduced
At Friday’s special session of the Transmission Expansion Advisory Committee, PJM officials said their review confirmed that LS Power’s proposal for a 230-kV line from Artificial Island to a new Silver Run substation in Delaware was the best solution but that the interconnection point should be changed from the Salem plant to Hope Creek. The analysis also determined that a static VAR compensator (SVC) at the New Freedom substation and optical groundwire upgrades provided little benefit and were unnecessary.
The planners’ recommendations will be forwarded to the board for final approval.
In addition to eliminating those upgrades from the scope of work, planners recommended implementing a voltage schedule at the plants and revising the in-service date to June 1, 2020.
Much of the discussion on Friday focused on the project’s costs compared to those of the other finalist, a project proposed by PSEG subsidiary Public Service Electric and Gas that would follow an existing transmission route north through New Jersey.
PJM’s analysis found that LS Power’s project would cost $265 million, $11 million more than PSE&G’s. But planners said LS Power’s proposal, which contained hard cost caps, provided “greater cost certainty.” PJM’s Paul McGlynn, who oversees the project’s development, said PSE&G’s project also raised permitting concerns because it would run through the Supawna Meadows National Wildlife Refuge.
PJM planners reaffirmed their 2015 selection of LS Power’s 230-kV circuit line to Delaware as the fix for stability problems at Artificial Island in New Jersey. Planners, however, determined that the line should connect Artificial Island at the Hope Creek nuclear generator rather than the nearby Salem plant. | PJM
As approved in July 2015, the project was expected to cost $270 million to $283 million. The February 2016 update that prompted the suspension pushed the cost to $418 million with the Salem interconnection more than doubling to $152 million from a maximum of $74 million.
Replacing the Salem connection with one at Hope Creek will save $20 million, and eliminating the optical ground wire and SVC trimmed an additional $120 million. That brings the projected cost to $265 million, with a cost cap of $278 million — within the bounds of the original project cost estimates.
PJM also pointed out that LS Power has already spent about $6.5 million on preliminary work, so switching projects would mean writing off that expense as a sunk cost. The RTO acknowledged that PSEG has also spent money on developing work estimates for PJM regarding its project but “didn’t think” to quantify it, said Vice President of Planning Steve Herling.
Stakeholders from PSEG and Dominion were among those criticizing PJM’s new recommendation.
More ‘Granular Review’
PJM said the suspension allowed time to conduct a “more granular review and re-evaluation” of the project, including additional site visits and marine and terrestrial surveying, a review of permits, property rights and scheduling issues and preliminary engineering.
Planners determined the optical groundwire and related line relay changes would not impact the site’s operating guide or improve stability margins because of the timing of the most critical bus fault’s clearing. They said if a need is identified for the upgrades later they would be pursued as a separate project.
The SVC was replaced with a recommend voltage schedule for Salem and Hope Creek requiring operation at a minimum of 527.5 kV, a level PJM said was “maintained in nearly all conditions since 2012.”
PSE&G insisted its proposal was “more robust” than LS Power’s, providing larger stability and system reliability margins and — because it would employ a 500-kV line — more than three times more capacity than its competitor’s 230-kV line.
PSEG’s nuclear division sent the PJM board a letter March 2 warning that it has an option to build another reactor at the Hope Creek station and that the connection at Hope Creek might have to be moved if it moves forward with another reactor. Herling said PJM has no control over that and that future work at the site would need to be reviewed on a “case-by-case” basis.
LS Power’s Sharon Segner said it’s not an “apple-to-apples” comparison because PSEG’s proposal excludes any overruns for environmental permitting and securing real estate rights, while her company’s includes risks for both. In addition, LS Power has already contracted for material portions of its project, so the revised, lower cost estimate of $133 million for its portion reflects some actual contractual numbers.
PSEG’s Jodi Moskowitz said that most of the costs in her company’s proposal are capped.
Old Dominion Electric Cooperative’s Mark Ringhausen said it was “deceiving” to use $265 million for LS Power’s project when that is only the company’s current estimate. The proposal is actually capped at $278 million. LS Power’s estimate assumes PSEG’s work at Hope Creek costs no more than $132 million. However, this portion of the project has no cost cap.
That wasn’t the end of the controversy, however. Delaware and Maryland officials have complained that most of the cost of the project would be allocated to ratepayers on the Delmarva peninsula despite the region receiving little benefit from the upgrade.
Last April, FERC approved the cost allocation for the project, but in June it said it would consider rehearing requests over whether PJM’s use of the solution-based distribution factor (DFAX) cost allocation method is appropriate for the project (EL15-95, ER15-2563). (See FERC Taking Second Look at Cost Allocation for 2 PJM Projects.)
The commission cannot resolve the dispute until new members are appointed to restore its quorum.
Next Steps
Herling said the board will be educated about all of the cost estimates through comprehensive documentation, and “I guarantee they’ll read all of it.”
The next board meeting is scheduled for April 6, so PJM asked that all stakeholder comments on the recommendation be filed by March 31. Stakeholders expressed concerns that PJM won’t have published its comprehensive whitepaper on the topic by then, so all comments will have to be based on existing documents.
Southwestern Public Service and SPP have asked Texas regulators to rule on whether Texas law includes a right of first refusal that overrides FERC Order 1000 (Docket No. 46901).
At issue is who will build a 90-mile, 345-kV line from Potter County to SPS’ Tolk Generating Station in the Texas Panhandle. Without a state ROFR, the project would be open to competitive bidding under Order 1000.
Tolk Generating Station | Xcel Energy
SPS and SPP asked the Public Utility Commission of Texas to determine whether the RTO can designate entities other than the incumbent utility to construct and own regionally funded transmission facilities in Texas outside the ERCOT service area.
SPS contends in the Feb. 28 filing that the Public Utility Regulatory Act (PURA) allows it, as the incumbent utility operating outside ERCOT, the ROFR to build in the service area prescribed by the PUC. That would prevent a potential competitive project under Order 1000.
SPP says there is “no clear statement in Texas laws” that incumbent utilities have such a right, and it is following the Tariff’s competitive bidding process until the commission “can resolve the issue as a matter of law.”
The ruling will determine who gets to build the Potter-Tolk line — the only one of 14 projects in the Integrated Transmission Planning 10-Year Assessment not approved by SPP’s Board of Directors and Members Committee in January. The board requested the project undergo further study and be brought back to its April meeting. (See “Board Sends $144M Tx Project Back for Re-evaluation,” SPP Board of Directors/Members Committee Briefs.)
SPS filed a lawsuit in a Texas state district court Jan. 18 seeking approval of its right to build the project and other 345-kV projects in its Texas service area. The utility also sought an injunction prohibiting SPP from issuing a notification-to-construct for the Potter-Tolk line to any company other than SPS.
However, the utility and SPP both agreed to temporarily suspend the lawsuit Feb. 27 and file with the PUC instead.
SPS spokesman Wes Reeves said the lawsuit against SPP and the subsequent PUC filing “are not … adversarial in nature.”
“We simply seek clarity on our first right as a non-ERCOT utility to construct and operate regionally funded transmission lines within our service area,” Reeves said.
In a statement, SPP General Counsel Paul Suskie said the two entities agree Texas law is unclear on ROFR issues.
“Our joint filing has been made with the intention of addressing that uncertainty,” Suskie said.
In Order 1000, FERC explicitly acknowledged that it could not override state ROFRs. SPS contends PURA’s legislative history confirms “transmission-only utilities are not permitted outside of ERCOT,” and that any holder of a certificate of convenience and necessity must “serve every consumer in the utility’s certificated area” and “provide continuous and adequate service in that area.”
SPP asserted that because no local Texas laws or statues would be violated by its competitive bidding process, it would treat the Potter-Tolk line as a competitive upgrade and would seek bids for the project.
The parties proposed an intervention deadline of 30 days following the petition’s publication in the Texas Register, set for March 17. Given the proposed schedule, it’s all but certain there will be no resolution before SPP’s April board meeting.
An administrative law judge gave the PUC until March 16 to file comments or make a recommendation. The PUC’s next scheduled meeting is March 9.
A financial trading firm accused PJM of unfairly discounting the interests of up-to-congestion traders in recent rule changes that it says would shift hundreds of millions in uplift charges to them from load.
“PJM is required to act as a neutral body without giving priority to one sector over others. XO is concerned that the packages promulgated by PJM and its [Independent Market Monitor] … benefits load while producing great harm to the Other Supplier Sector, including the financial community,” XO Energy President Shawn Sheehan wrote in a Feb. 24 letter to the Board of Managers.
The letter follows a phased set of rule changes that was overwhelmingly endorsed by the Markets and Reliability Committee in January and the Members Committee in February. (See “Work on Uplift Moves Forward Despite NOPR,” PJM Markets and Reliability and Members Committees Briefs.)
Phase 1 includes in the determination of balancing operating reserve credits only the day-ahead revenues from the hours the resource operated in real-time, not all day-ahead revenues. Phase 2 includes UTC transactions in the allocation of day-ahead and balancing operating reserves in the same way as incremental offers and decremental bids. It would also remove the ability for internal bilateral transactions to offset deviation charges.
XO argues in its letter that the changes create a “triple capacity deviation,” although UTCs are intrinsically transmission products that don’t impact capacity. According to XO’s calculations, the changes will shift as much as 79% of the total real-time uplift charges and 25% of day-ahead uplift to UTCs — a total of more than $388.5 million.
The letter argues that PJM actively worked to force the changes through the stakeholder process and didn’t offer XO and its allies due process.
“XO is concerned that equitable, stakeholder-centric initiatives, which do not comport with fundamental market design principles, such as best practices and causation, are taking precedence” to sound market design, the letter reads. “In the past year or more, XO has witnessed an unwarranted negativity from PJM and its staff towards both financial products and the financial trading community. … Financial market participants feel bulldozed by PJM’s perceived priority in advancing its own proposals through the voting process and its favoritism of other [stakeholder] sectors. These actions are strongly affecting market participants’ confidence in PJM’s ‘neutral’ administration of its duties and its operation of a fair and efficient market.”
PJM did not immediately respond to a request for comment.
The complaint is the latest chapter in a long-running battle among PJM stakeholders over the value of financial products such as UTCs and whether they are paying their fair share of costs.
XO contends that PJM ignored FERC’s direction in its proposed Phase 3 package that would limit UTCs to zones, hubs and aggregates. Such changes “would effectively remove the products’ ability to mitigate local market power and converge nodal congestion,” the company said. “FERC has repeatedly held that convergence of the day-ahead and real-time markets is a key measure of market efficiency.”
The Balancing Area of Northern California (BANC) has signed an agreement with CAISO that puts the Sacramento Municipal Utilities District (SMUD) on track to join the Western Energy Imbalance Market (EIM) in spring 2019.
The footprint of the Balancing Authority of Northern California extends north to south from the Oregon border to Modesto, and east to west from Sacramento to the Sierra Nevada range. | Balancing Area of Northern California
Another municipal utility, Seattle City Light, announced its interest in joining the market shortly after SMUD’s announcement and has already signed an agreement with the ISO, putting it on schedule to join up at the same time as the California utility. (See Seattle City Light Signs EIM Membership Agreement.)
The latest agreement calls for a “phased” approach for BANC members to join the EIM, with SMUD’s participation representing the first stage, followed by discussions regarding participation for other members, possibly including federal power marketing agency Western Area Power Administration’s Sierra Nevada region.
Regardless of whether WAPA eventually links up with the EIM, BANC members Modesto Irrigation District and the cities of Redding and Roseville are considering doing so. Two other members — the city of Shasta Lake and Trinity Public Utilities District — own no generating resources and would therefore derive no benefit from joining the market, according to Jim Shetler, BANC’s general manager.
The phased implementation hinges on SMUD being accounted for separately from other BANC members, including “having separate interchange as represented by e-tags, a separate area control error calculation, and separate revenue quality metering,” the EIM agreement states.
SMUD already has an agreement that enables the utility to bid power into CAISO through a single hub in which one proxy price is selected to represent all connection points between the two areas.
Another term spelled out in the agreement: CAISO acknowledges that as public entities, BANC members want to remain outside the jurisdiction of FERC.
BANC, in turn, accepts that its transmission-owning members will be required to amend their open access transmission tariffs to reflect the fact that the EIM’s operations are subject to FERC oversight.
“We believe the implementation agreement and our partnership with [the] ISO recognizes the unique situation of our public power members,” Shetler said in a statement. “We are pleased to begin the work that will enable our members to participate in the EIM if they choose to do so.”
Solano Wind Project in the Sacramento Municipal Utility District | Balancing Authority of Northern California
Incorporation of other BANC members in the future will require that the agreement be amended, or that a completely new one be executed.
CAISO CEO Steve Berberich said he was pleased with the decision by BANC and SMUD.
“SMUD is one of the premiere community-owned utilities in the country that will benefit from access to low-cost resources from the entire EIM footprint,” Berberich said.
SMUD has cited the benefits of increased renewable integration, potentially reduced reliance on gas-fired generation and lower operational costs as its primary reasons for joining the market — although the first two benefits outweighed the latter in the utility’s decision-making, according to Shetler. A joint study conducted by BANC and the WAPA estimated that SMUD would gain $2.8 million in yearly net benefits from transacting in the market, possibly increasing to $5 million in about five years — a “small number” compared with the utility’s overall portfolio, he said.
Established in 2011, BANC is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordinating Council. The agency contracts with SMUD to perform day-to-day balancing functions.
The Indiana Senate has approved a controversial bill that would phase out the state’s retail net metering program.
State senators voted 39-9 to approve Senate Bill 309, which gradually lowers the payments residents receive for selling excess energy from their distributed resources back into the grid. The bill now proceeds to the state’s House of Representatives.
Indiana residents currently earn the retail energy rate for their excess electricity, but the bill would reduce that compensation to 25% above the wholesale rate.
The bill originally contained a “buy-all, sell-all” provision that, if passed, meant homeowners would not have been able to use the power generated by their own solar or wind resources. Instead, they would have been required to sell all output to their local utility at wholesale, to be repurchased at retail. That provision was removed from the bill before the full Senate vote.
The bill underwent other amendments, including the addition of a grandfather clause — expiring in 2047 — for existing net metering customers and any residents who have equipment installed before July 1. Residents who sign up for net metering over the next five years would be covered under existing retail rate rules until 2032.
A provision that would altogether eliminate net metering by 2027 was also tossed from the bill.
The proposed law would also allow utilities to discontinue offering net metering in their service areas when net metering generation equals 1% of their peak summer demand load.
In a Feb. 22 opinion in Fort Wayne’s The Journal Gazette, bill author Sen. Brandt Hershman (R) praised the legislation, calling it a “net gain for Hoosiers.” The bill encourages “renewable energy generation while bringing more fairness and market sensibility to the way privately owned solar panels and wind turbines are subsidized by other customers,” he wrote.
Hoosier Energy Power Network Solar Power Plant in Bloomington, In. Inovateus Solar
Hershman said that having electric utilities pay full retail rates for consumer-generated energy is unfair and that the prices are “two to three times the actual value of the energy on the market.” Net metering was established to encourage investments in consumer-owned solar and wind generation when installation costs were higher, he contended, but the generation is now more affordable. He pointed out that the federal government has reduced its incentives for residential renewables.
The bill has found support from Indiana’s major utilities, according to Mark Maassel, president of the Indiana Energy Association, which represents major Indiana electric utilities Duke Energy, American Electric Power’s Indiana Michigan Power, Indianapolis Power and Light, Vectren and Northern Indiana Public Service Co.
“All Indiana’s investor-owned utilities are working together on this,” Maassel said. “The companies are very thankful for Senator Hershman.”
Maassel said the utilities did not have a hand in authoring or revising the bill.
“The bill, where we ended up at, is a positive step and something we would like moved forward,” Maassel said.
But solar and renewable advocates are not happy with the final product, arguing that the bill gives utilities too much control over residential solar and wind.
“Senator Hershman, Indiana’s monopoly utilities and their friends in the legislature who are backing the bill say it was ‘fixed’ with amendments, but that’s not true,” said Wendy Bredhold, an Indiana-based representative of the Sierra Club’s Beyond Coal campaign. “The utilities want to control solar power and take away Hoosiers’ freedom to generate their own.”
Bredhold called the bill a “step backwards” for Indiana and “energy freedom” and said that it “effectively kills homegrown, rooftop solar” in a state “controlled by powerful utility interests.”
The Indiana Distributed Energy Alliance said the bill “will eviscerate net metering and customer-owned solar and small wind in Indiana.”
Sean Gallagher, vice president of state affairs for Solar Energy Industries Association, said the bill’s language fails to account for the full range benefits that residential generation can provide.
“Compensating … local power at average wholesale prices, as SB 309 proposes, significantly undervalues the benefits of producing that power — such as avoiding the need to build new power lines — and ignores the fact that solar power is produced during daytime peak periods when wholesale energy prices are higher,” Gallagher said.
Gallagher has called on Indiana’s legislature to let the Utility Regulatory Commission investigate the costs and benefits of rooftop solar before setting “arbitrary limits or determining compensation that customers would receive in statute.”
