PJM’s Board of Managers announced in a letter to members last week that the Nominating Committee is recommending former InterGen CEO Neil H. Smith to replace Chairman Howard Schneider, who will retire from the board at the RTO’s Annual Meeting next month.
Smith
The committee also recommended re-electing current board members Neel Foster and Sarah Rogers. The Members Committee will vote on the candidates at the Annual Meeting.
Smith was selected following a national search, assisted by the Heidrick & Struggles search firm, that included candidates suggested by current board members. He retired from InterGen in 2016 after 25 years with the company, working his way up from development director.
InterGen operates 11 power plants with a generation capacity of 7,686 MW, three compression facilities and a 40-mile gas pipeline. The facilities are located in the U.K., Netherlands, Mexico and Australia. The company is jointly owned by the Ontario Teachers’ Pension Plan and China Huaneng Group/Guangdong Yudean Group.
Smith also served as a non-executive director and board member of The Wood Group, a worldwide service provider for the oil-and-gas and power generation industries. He was on the board for nine years, between 2004 and 2013, according to his LinkedIn profile.
Stakeholders learned Wednesday that MISO will delay for another year a plan to account for previously un-forecasted planned outages at times of peak demand after getting mixed feedback from market participants.
Speaking at an April 11 Resource Adequacy Subcommittee meeting, MISO Resource Adequacy Coordinator Ryan Westphal said the RTO will wait until the 2020/21 planning year to implement a new, unspecified calculation that accounts for planned outages during peak demand, which could increase the RTO’s planning reserve margin requirement.
MISO had proposed to factor the effects of planned and maintenance outages on peak in its loss-of-load expectation (LOLE) study by the 2019/20 planning year. (See MISO RASC Zeroes in on Priorities.)
Westphal said some stakeholders asked the RTO investigate further before making any changes to the LOLE study. Others urged it to define “safe” periods during the summer months to take planned outages.
Director of Resource Adequacy Coordination Laura Rauch said MISO would delay accounting for planned outages on peak until it develops solutions based on a more comprehensive conversation about the RTO’s shifting resource availability. (See MISO Looks to Address Changing Resource Availability.)
Some stakeholders expressed frustration that the RTO first presented the issue as requiring expeditious treatment, then moved it into a discussion about resource availability and needs, only to again this month single it out to proceed separately. (See MISO to Fold Outage Forecasting into Larger Resource Effort.)
Reprieve for Out-year Import and Export Limit Estimates
MISO is taking a cue from stakeholders and switching gears on a previous proposal to discontinue its practice of forecasting long-term capacity import and export limits, instead proposing to modify the process that produces the forecast.
MISO’s Matt Sutton said the RTO expects by early 2019 to revise its process for predicting capacity transmission limits for its 10 local resource zones. It had proposed in February to altogether scrap out-year import and export limits, saying results were too unreliable and volatile, but stakeholders countered that the limits provided useful information. (See “Scrapping Out-Year Import and Export Limit Estimates?” MISO Resource Adequacy Subcommittee Briefs: Feb. 7, 2018.)
While the RTO still plans to compile the long-term limit estimates, it will use more zone-specific information, including data from past Planning Resource Auctions and the Organization of MISO States-MISO annual resource adequacy survey.
Sutton said the RTO would not commit to annual restudies for capacity zones that don’t experience notable changes.
“If a zone could potentially bind, a study isn’t necessary every year unless a significant supply or transmission change occurs,” he said. “The number of studies is being reduced significantly. … We’ll have fewer zones to review.”
The selective study process will allow MISO to focus on zones that could bind on their import and export limits or carry capacity surpluses beyond their export capability, Sutton said.
The more thorough process to estimate out-year limits should spark discussions around new transmission and generation projects and the impact of external system changes on capacity zones, he said, not just the usual conversations about transfer limits, constraints and redispatch options.
MISO will pass its recommendations for improvements to its stakeholder-led Loss of Load Expectation Working Group, which will produce a new prediction methodology for stakeholder review as early as September, Sutton said. He asked stakeholders to submit written comments on the RTO’s plan by April 27.
Different Method for Economic Uncertainties in LOLE Study?
MISO is exploring how to improve its modeling of economic load uncertainties in the LOLE study.
For the 2018/19 planning year, the RTO relied on a GDP growth comparison to account for the uncertainties, which increased the annual planning reserve margin by 0.2 percentage points year-over-year.
In June, MISO will have a 17.1% planning reserve margin, which represents the extra generation the RTO should have on hand to meet a probability of shedding load no more than one day in 10 years. MISO maintained a 15.8% planning reserve margin in the 2017/18 planning year.
MISO staff have attributed the increase to an upswing in generation outages and a change in the dispatch model for demand resources, but it was partially offset by reduction in anticipated load growth. The RTO last year also added the new modeling step to capture economic load uncertainty that increases risks associated with high peak loads, which also boosted the reserve margin. (See MISO Planning Reserve Margin Climbs to 17% for 2018/19.)
“We’re reviewing our methodology and investigating other approaches for the 2020/21 planning year model,” MISO Resource Adequacy Senior Engineer William Buchanan said.
In future years, the RTO may model economic uncertainty using a calculation based on comparisons between forecasted and actual demand in past years, Buchanan said.
New Jersey lawmakers on Thursday passed a pair of bills that could significantly shape the state’s generation portfolio over the next decade.
One bill would provide two Public Service Enterprise Group nuclear power plants with subsidies costing ratepayers about $300 million per year. The other would require the state’s power sellers to get half their electricity from renewable sources by 2030.
New Jersey’s State Capitol Building
By a 29-7 vote, the state Senate passed S2313, which would create a zero-emission certificate (ZEC) subsidy for nuclear plant operators that can show the New Jersey Board of Public Utilities their plants need financial support to remain operating. The bill passed the General Assembly on a vote of 60-10.
The bill now goes to Gov. Philip Murphy, who will have 45 days to decide whether to sign the bill, veto it or allow it to become law without his signature. He could also conditionally veto the bill and send it back to the Legislature with proposed changes.
ClearView Energy Partners gave Murphy a 65% chance of signing the bill but said he may conditionally veto it, in which case the Legislature could agree to his proposed changes with a simple majority vote. If he vetoes it, the Legislature would need a two-thirds majority vote for the bill to become law.
If Murphy does sign the bill, ClearView says it expects opponents will file a lawsuit in the U.S. District Court for New Jersey challenging the ZEC program on grounds similar to those of lawsuits challenging similar programs in New York and Illinois. ClearView also said it thinks New Jersey lawmakers structured their state’s ZEC program with such lawsuits in mind.
The nuclear subsidy bill drew a mixed reaction. The Natural Resources Defense Council has said it will not oppose the bill, while Jeff Tittel, director of the New Jersey Sierra Club, said it would have “a chilling effect on spending more for renewable energy, because to build out renewable will cost much more.”
The Electric Power Supply Association and New Jersey Petroleum Council also panned the nuclear bill, while PSEG spokesman Michael Jennings called it “a sensible solution that protects the viability of nuclear energy and its benefits for New Jersey, while at the same time ensuring consumers are protected, as well.”
The other bill (A3723) would require electric power suppliers to procure 35% of their power from renewable resources by 2025 and 50% by 2030.
KANSAS CITY, Mo. — While Midwestern grid planners aren’t certain about the future of energy infrastructure, they do agree that planning must yield to a convergence of trends, including low-cost renewables, energy storage, escalating cyberattacks, flat demand and legacy generation verging on the antique.
Those trends will dictate the direction of new buildouts, according to industry experts speaking Tuesday on a infrastructure panel as part of the Midwest Energy Policy Series hosted by the Missouri Energy Initiative.
Missouri Public Service Commission Chairman Daniel Hall said new infrastructure placement must take into account a blend of national trends, including declining wind and solar costs, the natural gas fracking boom, aging power plants and transmission lines, and declining demand for electricity due to household energy efficiency and the country’s downsized manufacturing sector.
“Most distribution lines were constructed in the 1950s and 1960s, and they were expected to last 50 years,” Hall said.
Many utilities are planning utility-scale renewable projects, he said, pointing out that Ameren has requested a certificate of convenience and necessity for a 700-MW wind farm by 2020.
“If completed, that would account for almost 10% of Ameren’s power generation,” Hall said.
While renewables could fill in for aging baseload generation, RTO planners questioned whether the demand-light Midwest needs an abundance of new generation development. Other panelists agreed that years of 3% annual load growth are a thing of the past.
SPP Manager of Transmission Services Charles Cates said SPP’s queue holds 70 GW of generation, which, if built, would exceed the RTO’s current peak loads.
David Van Beek, MISO external affairs manager, said his RTO is still experiencing a “drastic generation shift” toward renewables even with the uncertainty surrounding the Clean Power Plan. He noted that solar projects account for one-third of MISO’s record-setting 90-GW-plus generation interconnection queue.
The Promise of Storage
Even with the addition of all that proposed generation, panelists said storage projects could facilitate local consumption of the output, precluding the need for the new transmission lines planned for in the past.
Jay Lohrbach, manager of generation projects for City Utilities of Springfield, Mo., said a joint 1-MW battery storage project between his utility and NorthStar Battery at the Cox substation will likely defer the need to build transmission infrastructure in that area.
Lohrbach said that by the end of 2019, the utility will be supplying the city with 40% renewable power.
“This is Springfield, Mo., not California,” Lohrbach reminded the audience. “That’s amazing.”
Lohrbach said utilities are in the unenviable position of balancing when to retire uneconomic and slow baseload coal and nuclear units with a duty to provide capacity. “The bar has been placed pretty high in how efficient we have to be,” he said. “It’s a tough situation economically for utilities.”
He said NorthStar’s batteries can be designed exclusively to manage small spikes of demand, catering to a country with otherwise flatlining loads.
“Battery storage can scale down to the size of your house pretty readily,” Lohrbach said. He added that storage batteries have no fixed costs, only upfront construction costs and fairly well-defined variable costs.
“It’s pretty easy to decide when to discharge the battery,” Lohrbach said. “And if I don’t deploy it, it can just sit there and not cost me anything. It’s a completely different economic model than anything we’ve seen before, and we need to wrap our heads around it.”
Lohrbach said RTO transmission planners aren’t yet planning for the full impact of storage developments.
In response to an audience member’s question about the prospect of planning transmission explicitly to accommodate energy storage in the wake of FERC’s Order 841, Van Beek said the order was too new to shape transmission planning. Both this year and last, MISO incorporated a fourth future scenario into its transmission planning process as distributed and emerging technologies become more widely used. (See MISO to Recycle Tx Planning Scenarios for 2019.)
Chris Neaville, asset development director of St. Louis-based mining company Doe Run, said large industrial consumers also want storage projects.
“We think the future for us is really developing our own microgrid,” Neaville said.
Doe Run envisions a microgrid that could shave its peak loads through 21 to 50 MW of behind-the-meter, onsite solar power and up to 16 MW of battery storage, which could also serve as back-up generation for its mines’ critical systems.
“We could become interruptible load,” Neaville added.
He said electricity is Doe Run’s single biggest operating cost at about $23 million annually, and that 1960s-era transmission lines deliver power to its remotely situated mines.
Neaville said he’s worried that Ameren is currently being granted about 5% rate increases about every 18 months, with each hike subtracting about $2 million to $3 million from the company’s bottom line.
“Our concern for the future is that if it continues at that rate, it’s not sustainable,” Neaville said. “There’s a break point where we have to do something differently. We can’t keep increasing these rates.”
Doe Run would prefer not to build its own generation, Neaville said, so the company hopes to partner with a utility on a microgrid project.
Grain Belt Express
Discussion veered to Clean Line Energy Partners’ embattled, high-voltage Grain Belt Express transmission project, whose fate is now in the hands of the Missouri Supreme Court. The stalled $2.3 billion, 780-mile line was designed to transmit Kansas wind generation to the western border of Indiana after crossing Missouri and Illinois.
Hall said that although the Missouri PSC found the project worthy, its hands were tied in denying the application because the Caldwell County Commission refused consent for the transmission line to cross public roads.
He said the commission was bound to follow the Western District Court of Appeals’ decision that the certificate could not be lawfully granted without county approval.
“That is essentially a road map for county commissioners to focus on their voters. … It doesn’t make sense from my perspective that you’ve got county commissioners that can decide the fate of interstate transmission lines,” Hall said.
Clean Line’s situation highlights the need to either change state law or have the federal government supersede state jurisdiction, he said.
“Hopefully, the [Missouri] Supreme Court will get it right.”
Hall also hopes the court’s opinion “would not say that the PSC erred” in denying the certificate, as the commission was legally bound to issuing a denial.
Van Beek and Cates discussed whether their RTOs would approve a first-ever interregional project along their seam, especially near Kansas and Missouri. Both agreed their two-year joint modeling process can sometimes delay project approval.
“The time frame of modeling is quite extensive,” said Cates, adding that while the RTOs’ can usually agree about what areas need a transmission project, they can get stuck on how to divide costs. MISO and SPP staff have recently suggested abandoning their joint model in favor of more closely aligned regional models. (See MISO, SPP Look to Ease Interregional Project Criteria.) The two RTOs plan to wait a year before embarking on another joint study in hopes of improving their process to gain approval for an interregional transmission project.
ITC Holdings’ Chris Winland said his company wants to be on the “cutting edge” of planning transmission infrastructure for future wind developments in Kansas and Oklahoma. He said those areas are home to the “best wind in the country” and predicted more development.
Whatever infrastructure is built, it needs to withstand increasingly sophisticated cyberattacks, said Ameren Chief Information Officer Mary Heger.
Ameren uses a combination of systems monitoring, virus scanning, network segmentation, quarantine programs for suspect email and “whitelisting” — which authorizes which applications are allowed to run, thereby excluding all other programs, she said.
“The program we put in place is designed to protect us against a broad scope of actors.”
Heger said Ameren also has an in-house training program called Cybersafe, where the utility will test employees by sending simulated phishing emails — the kind of which that set in motion the 2015 cybersecurity attack on Ukraine’s grid.
“People really are one of the weakest links,” Heger said.
“As long as people click on links … that will be a very popular way to get a foot in the door,” said Galen Rasche, Electric Power Research Institute senior program manager.
Rasche said a more mobile utility workforce, dynamic supply and demand balancing, increasing automation of operations, customer self-generation and home energy management programs all create more opportunities for cyberattacks.
He said an integrated — or “multiparty” — grid, in which generation and storage assets are not necessarily owned and operated by utilities but are aggregated by a third party, presents a more complex security challenge. He predicted that some aggregation vendors will go out of business within five years and asked what will happen to their data after they fold.
“Cybersecurity now can’t be the sole responsibility of the utility,” he said. “We need to make sure we’re having this conversation with everyone in the room.”
KANSAS CITY, Mo. — A small group of SPP members have asked the Board of Directors to reconsider its decision to move forward with the Mountain West Transmission Group’s integration until “there is more consensus within the SPP membership as to how to proceed.”
In a letter filed for inclusion in the background materials for the board’s April 24 quarterly meeting, the group called for reopening negotiations with Mountain West to create a path “towards a single RTO with a single set of rules for all participants.”
It reflects growing stakeholder concerns over the board’s March 13 approval of policy recommendations intended to govern the terms of Mountain West’s membership in SPP. The board approved 18 policy statements and directed staff and stakeholders to begin revising SPP’s Tariff, bylaws, membership agreement and other governing documents. (See SPP Begins Work of Integrating Mountain West.)
The letter, dated April 6, was signed by load-serving entities Kansas City Power & Light, Municipal Energy Agency of Nebraska, Nebraska Public Power District, Oklahoma Gas & Electric and Western Farmers Electric Cooperative.
No Prior Notice
It charges that SPP’s full membership did not see the policy recommendations — such as new Mountain West-only stakeholder systems to manage regional cost allocation and zonal rate design — prior to board approval.
Based on the analyses presented so far, it is impossible for the board and stakeholders “to evaluate the potential impacts associated with the East-West bifurcation of SPP’s governance structure,” the companies said.
“The process has afforded neither the ability of the existing members to be well-informed nor the opportunity for the policy recommendations to be supported by the collective membership,” the five utilities wrote. “We want to see one set of rules applied to all entities — East and West — unless there is a physical or legal limitation (e.g., federal exemption) that must be honored. Any expansion of SPP to include new transmission-owning members must be designed so that both SPP’s existing members (and thus their customers) and the new entrant receive benefits. And if existing SPP customers are assigned additional costs, there should be corresponding benefits.”
MOPC Discussion
Separately, OG&E’s Greg McAuley brought the issue to the fore as SPP’s Markets and Operations Policy Committee meeting ended Wednesday. He asked that the minutes note as “we participate in the working groups [on Mountain West’s integration], it should not be reflected as overall acceptance of the proposal.”
“We’re still opposed to the Mountain West integration as proposed,” McAuley said. “Some of the revision requests are very complicated. They’re very difficult and complex, and they need to be reviewed appropriately. We don’t want our participation in that work to be viewed as demonstrating approval of the overall proposal or, conversely, intentionally slowing the process of getting the revision requests approved.”
Saying he did not want to leave McAuley “hanging out there by himself,” American Electric Power’s Richard Ross said his company also has “significant reservations about the structure of the proposal.”
“We don’t feel like it’s as good as it could have been done or should have been done. It brings risk to the existing membership,” he said. “But we will work through the stakeholder process. When given lemons, we’ll try make as good a batch of lemonade for the RTO as possible.”
One of AEP’s concerns is the cost of potential upgrades to the four DC ties connecting SPP and the Mountain West entities. The upgrades have been proposed as an approximate 70-30 split on a load-ratio share between East and West. SPP and Mountain West say that incorporating the ties into the RTO’s market will lead to lower production costs and savings from sharing operating reserves.
Yet to be determined is what happens should any Mountain West entities leave the expanded RTO after the DC ties are upgraded.
“I don’t want be in a situation where new members join and then they turn around and leave, and I have to continue paying for their DC-tie cost under the exiting provisions of the bylaws,” Ross said.
SPP: Not Surprised
SPP said the pushback was not unexpected, noting that its stakeholder process is built around collaboration, consensus-building, candor and open dialogue.
“In short, concerns expressed by our members to our board is a natural part of our established process, and we welcome dialogue with them,” the RTO said in a statement. “Now that we’re transitioning to a more public, inclusive phase of the integration process, we fully expect and welcome questions from our members regarding implementation of the board-approved policies.”
Xcel Energy spokesman Mark Stutz, speaking for the Mountain West entities, pointed out the SPP board’s March approval was of policy terms agreed to by the group’s utilities.
“The Mountain West members are now engaged in the public stakeholder process to develop the implementing language in the SPP Tariff and related contracts. Although final decisions have not been made, we plan to continue work in the established SPP public stakeholder process to complete these efforts,” Stutz said.
$500 Million not Sufficient
There was little other public support for McAuley and Ross at the MOPC meeting, but away from the microphones, stakeholders said the $500 million in total net benefits promised by SPP to existing members over the first 10 years of Mountain West’s membership is not sufficient.
They also expressed concerns about the time needed to vet Tariff and governance revisions and the exit provisions for Mountain West entities. SPP has said it hopes to bring a package of revision requests to the board in July for its approval.
Sunflower Electric Power Cooperative’s Tom Hestermann asked SPP COO Carl Monroe what was the sense of urgency driving the stakeholder process. Hestermann noted that the Regional Tariff Working Group has scheduled 17 meetings (five of which are multiday affairs) before the July 31 board meeting to manage the 12 revision requests before it.
“It’s always an issue of how do you ensure there’s due diligence,” Monroe said. “When setting a schedule, how do you ensure the parties have adequate time and the urgency to get something done and also have the ability to push back when key issues arise that need to be resolved. That’s the goal that’s been set.”
The Market Working Group faces a similar work load. It has scheduled seven meetings before the board meeting to handle the 20 Tariff changes it currently faces.
Monroe also told stakeholders that SPP and Mountain West are still negotiating a transition service agreement, but that staff have “every intention” of providing “all the protections that have been requested” should Mountain West walk away from the deal.
He said SPP has exhausted the funds allocated by the Finance Committee for integration work, which has led to a temporary halt in the effort.
“We’re not doing anything for integration until they sign the agreement,” Monroe said. “We’re pushing to get it done.”
SPP projects it will take about two years to fully integrate the Mountain West entities as members, but it plans to begin reliability coordination services in late 2019.
MISO’s sixth annual Planning Resource Auction cleared at $10/MW-day in all but one zone, a nearly seven-fold jump over last year’s single clearing price of $1.50/MW-day.
The RTO reported clearing 135 GW of capacity on Thursday, with nine of its 10 local resource zones clearing at $10/MW-day. The lone outlier was Zone 1 — covering parts of Wisconsin, Minnesota and the Dakotas — which cleared at $1/MW-day. MISO’s Independent Market Monitor has reviewed and certified the results.
“This year’s auction results reflect an adequate availability of resources for the planning window and the grid’s capability to effectively and efficiently transfer resources among local resource zones,” MISO Executive Director of Market Operations Shawn McFarlane said in a press release.
| MISO
MISO said this year’s price increase was driven by “an increase in the planning reserve margin requirement, a decrease in supply and changes in market participant offer behavior.” Come June, the RTO will have a 17.1% planning reserve margin, based on limiting the likelihood of shedding load to no more than one day in 10 years.
MISO Manager of Resource Adequacy John Harmon on Friday said zero-price offers declined compared to last year’s auction.
“It does seem that participants had a greater appetite for risk,” Harmon said.
MISO maintained a 15.8% planning reserve margin for the 2017/18 planning year, when all zones cleared at $1.50/MW-day. Last spring, CEO John Bear said that the 2017/18 price resulted from high supply and low demand. (See All Zones at $1.50/MW-day in 5th MISO Capacity Auction.)
The last two auctions were a departure from three years ago, when almost all of MISO Midwest cleared at $72/MW-day for 2016/17, and four years ago, when Illinois’ Zone 4 cleared at $150/MW-day for 2015/16.
The RTO also said auction results were in line with the results of last year’s Organization of MISO States-MISO resource adequacy survey, which predicted sufficient capacity to meet near-term planning requirements through 2022. (See Capacity Survey Shows MISO in the Black.) McFarlane said the results demonstrate the “grid’s capability to transport those megawatts across the zones.”
MISO said this year’s auction continued the increase in non-traditional resources. About 1,600 MW of additional demand response, energy efficiency and behind-the-meter generation cleared, bringing the total to 11,000 MW, 8% of all resources. McFarlane said the increasing use of load-modifying resources to meet capacity needs underscores the need for MISO to continue its discussions on resource availability and need. (See MISO Looks to Address Changing Resource Availability.) The RTO said it will “continue to focus on the importance of long-term resource adequacy as the industry and generating fleet continues to evolve. MISO will also continue to support state processes around resource adequacy planning.”
During a Market Subcommittee meeting Thursday ahead of the auction results, Independent Market Monitor David Patton said he expected low auction capacity prices to continue “indefinitely.” In late February, FERC rejected the Monitor’s latest request to order MISO to apply a sloped demand curve, which he said would result in more efficient pricing. The commission said the RTO’s vertical curve was just and reasonable, noting that 90% of load is served by vertically integrated utilities. FERC also said pricing takes a backseat to the auction’s main objective to maintain reliability. (See FERC Vacates, Upholds MISO Resource Adequacy Rules.)
Zone 1
Harmon said 142 GW was offered in this year’s auction, 4 GW above the reserve margin requirement even when factoring in capacity stranded by transmission constraints, which would’ve accounted for another 2 GW in excess capacity.
“Zone 1 did bind on its capacity export limit this year. This binding did occur on the same transmission facility as last year,” Harmon said during an April 13 conference call with stakeholders.
WPPI Energy’s Steve Leovy expressed concerns over improper binding and price separation in Zone 1. In stakeholder meetings, Leovy has repeatedly called attention to MISO’s capacity export limit, which does not distinguish imports sourced outside the RTO from those sourced inside, making available transmission capacity appear scarcer than it really is, according to Leovy.
“I wouldn’t expect that line to bind. I would expect that line to have a lot of slack,” Leovy said. He said MISO must change the calculation behind its capacity import limits.
MISO staff on the conference call promised more information on capacity export limits and the RTO’s simultaneous feasibility test at the May 9 Resource Adequacy Subcommittee meeting.
Consumers Energy’s Jeff Beattie said it would be helpful for MISO develop a presentation showing how transmission capacity might increase around Zone 1 when the RTO’s multi-value transmission projects come online.
Winter is coming — or at least it will be coming again — and the PJM Board of Managers wants at least some energy price formation restructuring by then.
In a letter to stakeholders released on Thursday, the board acknowledged the heavy lift that implementing staff’s original price formation white paper might entail, but it said there is consensus between PJM staff and the Independent Market Monitor on changes to improve reserve pricing. The letter directs staff to identify changes that can be implemented for next winter and “respectfully requests stakeholders to deliberate timely” so that the revisions can be completed by the third quarter, in time for FERC approval for winter 2018/19. (See “Additional Reserves Needed?” PJM MRC/MC Briefs: March 22, 2018.)
The graphic explains the issue PJM hopes to resolve with its energy price-formation restructuring. | PJM
“We have been informed that PJM staff and the IMM agree that PJM should implement a 30-minute reserve product in real time to comport with the current day-ahead scheduling reserve product, address issues with the current implementation of the synchronized reserve market, implement a more dynamic establishment of reserve requirements so as to better capture operator actions taken to maintain reliability, and enhance the operating reserve demand curves used to price reserves during reserve shortage conditions,” the board wrote.
“Given the level of agreement between the IMM and PJM staff, the board believes that this more targeted issue may present an excellent opportunity for the stakeholder community to come together and demonstrate that the PJM stakeholder process can deliver thoughtful and timely consensus action.”
Dual Issues
The board reiterated its position that energy and reserve market pricing issues must be examined because “there are times when operators commit resources to ensure reliability but these commitments are not reflected through market clearing prices such that those prices can be suppressed and result in undesirable outcomes.”
The energy market issue has been the focus of the Energy Price Formation Senior Task Force, which is considering the revisions proposed in PJM’s white paper as part of a wider stakeholder analysis. (See “PJM Pushes Price Formation Plan,” FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
“The board is well aware of questions stakeholders have raised regarding this proposal. The board has listened to stakeholders and appreciates that changes to the LMP calculation require careful consideration,” the board wrote.
In recent PJM stakeholder meetings, the reserve market issues have become the central focus.
“We are hopeful that on an issue such as this one where there appears to be ample, empirical evidence that a market design change is needed, where there is significant alignment between PJM staff and the IMM concerning the need for change, and where there is clear direction as to the nature of the improvement required, such timely consensus can be achieved,” the board wrote.
It asked that the remaining issues be resolved by the first quarter of 2019 so they can be approved and implemented by the summer of 2019.
“Such timely action, if it can be achieved, will reinforce confidence in the ability of the stakeholder process to deliver timely consensus solutions,” the board wrote.
FirstEnergy Solutions’ bankruptcy is creating repercussions that extend beyond the question of whether the merchant generator will survive.
While speculation had been swirling for months that FES, FirstEnergy’s generation arm, would soon go under, the company’s March 31 bankruptcy filing was overshadowed by its announcement that it was shuttering nearly 4,000 MW of nuclear generation and requesting an emergency order from the Department of Energy to keep its ailing fleet running. (See FES Seeks Bankruptcy, DOE Emergency Order.)
As part of its bankruptcy filing, FES requested the authority to end its long-held “sponsorship” of the Ohio Valley Energy Corp. (OVEC) and block FERC from making any ruling on the issue. FES requires FERC approval to void its inter-company power agreement (ICPA) with OVEC.
OVEC responded by petitioning the U.S District Court for the Northern District of Ohio to withdraw the request, contending that FERC has exclusive authority over wholesale power agreements that can’t be addressed by a bankruptcy court. The court denied that argument and found that FERC and the bankruptcy court have “concurrent jurisdiction” over the companies’ ICPA.
“Thus, FES must seek approval from both FERC and the Bankruptcy Court to reject the ICPA. FERC will apply the [Federal Power Act’s] public interest standard to determine if the rejection comports with federal law,” the court said.
Clifty Creek Power Plant Complex | Crowezr
OVEC, headquartered in Piketon, Ohio, is still awaiting FERC’s decision on a complaint (EL18-135) it filed on March 26 in anticipation of FES’ filing.
Under the current ICPA, which runs through June 30, 2040, OVEC provides power from its two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — to its eight corporate “sponsors” that include FES. The units are already pseudo-tied into PJM, and the sponsors can sell their portions of the output into the RTO’s markets.
Kyger Creek Power Plant
OVEC has been granted permission to join PJM as of June 1 but will have no load after a DOE contract ends sometime before 2023. The company was created in 1952 to service a uranium enrichment plant near Piketon that ceased operations in 2001. The department ended the 2,000-MW contract in 2003; it maintains a load that can be 45 MW at its maximum but is generally less than 30 MW.
While the sponsors are not required to sell their output, they are required to pay their portion of OVEC’s costs. There is no requirement for the other sponsors to make up for any shortfalls from companies that don’t pay. FES has a 4.85% stake, equating to about $30.1 million annually, according to OVEC’s federal court complaint (5:18-mc-00034-DAP).
PUCO Concerns
Separately, the Public Utilities Commission of Ohio has opened an investigation (18-569-EL-UNC) into FES’ retail sales and its future marketing plans in light of revelations that the company is still offering consumer contracts for up to three years. PUCO gave the company until May 4 to file a detailed explanation about whether it plans and is able to continue its retail sales business.
The order came a day after FES confirmed during its initial bankruptcy hearing on April 3 that it has contracts with more than 900,000 retail customers and plans to sell them to other suppliers. A day earlier, FES had filed a notice with PUCO in its relicensing case (00-1742-EL-CRS) that the bankruptcy wouldn’t affect its retail operations. The company must seek relicensing every two years to be a retail energy supplier.
Nuclear Energy Institute CEO Maria Korsnick on Thursday expressed support for FirstEnergy Solutions’ request that the Department of Energy declare an emergency in PJM to prevent the shutdown of the company’s three nuclear plants.
Korsnick | NEI
But she called the request — along with state zero-emission credit (ZEC) programs — a “bridging strategy” for the industry: temporary measures to keep the plants afloat until RTOs/ISOs and FERC reform wholesale market price formation.
“Ultimately, the fix that’s needed is that recognition [of nuclear’s emissions-free output] in the marketplace. That recognition has been a bit slow in coming, which is why you’re seeing the level of activity that you’re seeing at the state level,” Korsnick said. “The long-term answer is going to be one that’s market-driven.”
Korsnick was responding to a question submitted through a Facebook Live webcast of NEI’s Annual Briefing for the Financial Community. After giving a speech on the state of nuclear industry, she answered questions, which were also submitted by email, relayed to her by NEI spokeswoman Monica Trauzzi.
In both her speech and answers to questions — some submitted by NEI staff, Korsnick was nonspecific about the issue of price formation. She instead consistently came back to the value of nuclear as a contributor to states’ carbon-reduction goals and a “resilient” source of electricity. She praised ZEC as an example of good state policy and noted that Maryland and Washington are considering carbon taxes.
Monica Trauzzi (left), Nuclear Energy Institute senior director of external communications, relayed questions submitted by Facebook and email to CEO Maria Korsnick during a webcast. | NEI
“The pursuit of clean energy can threaten our nuclear plants if we don’t do it thoughtfully. If the goal is to reduce emissions, then all zero-emission technologies must be part of the solution. We must recognize what we already have in place and build on that. Replacing zero-emitting technology with other zero-emitting technology won’t help.”
She also applauded Congress’ extension of nuclear production tax credits to allow the construction of Georgia Power’s Plant Vogtle Units 3 and 4 to be completed.
But Korsnick warned that generation owners plan to prematurely close 12 reactors and that “if nothing is done to save these plants, the impacts will be devastating.”
“If all of these 12 plants close, we will lose over 120 million MWh [per year] of carbon-free generation,” she said. “That’s equal to half of all the megawatt-hours of wind electricity generated last year in the United States.
“We can stick with a myopic focus on short-term prices. Or we can strive to preserve a resilient, robust electricity system, jobs, tax revenues, clean air and healthy communities.”
To counter the grim warnings, Korsnick highlighted positive developments in the industry. She pointed to NuScale’s small modular reactor design, which she said is “progressing well” through the Nuclear Regulatory Commission, and to the Trump administration’s support for Saudi Arabia’s plans for as many as 16 nuclear reactors.
“The export market is growing, and our success there will strengthen the U.S. supply chain and its support of the existing U.S. fleet,” she said.
WASHINGTON — Panelists at day 2 of FERC’s technical conference on distributed energy resources (AD18-10, RM18-9) debated whether electric distribution companies (EDCs) should serve as gatekeepers or facilitators for resources seeking to participate in energy markets.
EDCs and their allies said they should have control over DERs on their systems, while DER supporters called for strict criteria on utilities’ ability to block DERs.
The first day of the conference focused on how RTOs and state regulators can craft policies that encourage DER to participate in wholesale markets while minimizing the burden on grid operators. (See RTOs, Regulators Set Course for DER Market Participation.)
Conflicts of Interest?
Audrey Lee, vice president of energy services for residential solar and storage provider Sunrun, said EDCs should only be allowed to block DERs through a showing that they would endanger system reliability.
“I think we need some specific examples [of problems] before creating any rules on this,” she said, adding that utilities seeking to install their own resources could have conflicts of interest. She noted that CAISO’s Tariff gives EDCs a deadline for reviewing DER applications and reserves the final decision for the ISO.
Maria Robinson, director of wholesale markets for Advanced Energy Economy, said distribution companies “should be facilitators, not a gatekeeper … preventing the ability of [DER] aggregators to enter.”
She suggested EDCs identify zones that can absorb DERs without reliability problems. If they are to review DER applications, EDCs should be given deadlines requiring them to act quickly, and rejected applicants should have the right to appeal to the RTO/ISO or FERC, she said.
“The vast majority of issues should be worked out with the interconnection agreement” between the resources and transmission operator, she said, adding that reviews should be done only once for each interconnection.
Pete Langbein, manager of demand response operations for PJM, also said interconnection studies should consider DERs once, as opposed to “iteratively.” The studies “may evolve over time” to provide the information needed to evaluate DERs’ impact, he acknowledged.
Interconnection Agreements not Enough
But David K. Owens, retired executive vice president of the Edison Electric Institute, said EDCs need to know DERs’ attributes to understand which ones could cause system disturbances. “Just having a list of aggregators is not sufficient,” he said. “[Distribution] utilities have to know when DERs are deployed. … Interconnection agreements alone will not do it.”
Jeff Taft, chief architect for Pacific Northwest National Laboratory, said DERs become potentially more disruptive as their density increases and that the effects are more significant on distribution lines. “The closer you get the edge of the distribution system, the more you see the volatility caused by DERs,” he said.
Taft said that although distribution lines are generally designed as radials rather than the “mesh” network of transmission, they are “dynamic” because EDCs reconfigure their systems daily. “A resource that may be running through substation A, a few minutes later may be running through substation B.”
State ‘Opt-out’
David Crews, senior vice president of power supply for East Kentucky Power Cooperative, said EDCs must have authority to protect their systems to avoid imbalances on distribution feeders. He disagreed with projections that DERs will be evenly distributed, saying they are more likely to be clustered in wealthier areas where residents can afford solar panels and storage. “It can cause problems; I’m not saying it will.”
Crews also said state regulators should have the ability to “opt out” from allowing retail customers to participate in wholesale markets. EKPC joined PJM in 2013 based on an agreement with Kentucky regulators that state residents would not be able to participate in the RTO’s markets, he noted.
Crews said there is little use of solar and storage among EKPC’s 16 distribution utilities, which use five different makes of meters. “For us to go through the administrative cost of developing a tariff is burdensome to our members” at current penetration levels, he said. “If our members have enough [resources] out there that they want it, we’ll do it.”
Cross Purposes
Mark Esguerra, director of integrated grid planning for Pacific Gas and Electric, warned of conflicts between DERs transacting with RTOs/ISOs and ones providing services to distribution companies. “You could have a situation that none of the parties — the ISO and the distribution utility — get the response they’re looking for.”
Esguerra said the 10-day EDC review deadline suggested by some “could be a challenge without more sophisticated modeling tools.”
Missouri Public Service Commission Chairman Daniel Hall, vice president of the Organization of MISO States, said state regulators should set criteria for DER registration and that EDCs must have authority to approve DERs on their systems. “All distribution systems are unique and the people who know them best are the people on the ground, which is the utility and the utility’s regulator.”
Hall said clear criteria on when EDCs can reject DERs will keep EDCs honest. “That gets us beyond the gatekeeper/facilitator” debate, he said.
There was general agreement that RTOs/ISOs, EDCs and aggregators will need to develop new communication protocols to manage higher levels of DERs. Hall urged FERC to allow regional differences by allowing each RTO and its stakeholders to develop their own rules, subject to commission approval.
Gerald Gray, the Electric Power Research Institute’s (EPRI) program manager for information and communication technology, said that although some utilities do not have supervisory control and data acquisition (SCADA) at all substations, the expansion of advanced metering infrastructure means “there is a lot of granular data providing visibility” on distribution systems.
But Matthew Glasser, a director at Consolidated Edison, said his company and other New York utilities do not have the visibility they need to manage DERs. “Communication with DERs now is low-tech. It’s phone and emails.”
Joseph Ciabattoni, PJM’s manager of markets coordination, said the RTO typically communicates — via phone — with transmission operators, which do the same with their DERs.
Brandon Middaugh, senior program manager for distributed energy for Microsoft, said ISOs and RTOs have “very limited visibility into distribution.”
Visibility also was the subject for the first panelists of the morning — five of eight of whom were from grid operators or utilities. As Portland General Electric Vice President of Transmission and Distribution Larry Bekkedahl put it, system operators “can’t manage what you don’t measure.”
Bekkedahl said the information would allow utilities to avoid overbuilding capacity to the “worst-case scenario,” as is done today, and instead “put in as much capacity as necessary.”
Jens Boemer, the principal technical leader of EPRI’s Transmission Operations and Planning Group, said he learned from experiences in his native Germany that any data that can be collected “relatively easily” should be done “as early as possible” because it becomes more expensive to do it later. He also said it’s important to stop combining DER performance with load because it masks the additional services it provides.
Clyde Loutan, a principal on renewable energy integration for CAISO, said DERs contribute to the unpredictability of load. “We have system operators trying to control a grid with unpredictable demand and variable supply, so we’re always in reactive mode,” he said.
Donnie Bielak, PJM’s manager of reliability engineering, called that “a scary thought,” because the RTO watches CAISO as a barometer of what’s to come on DER issues. “We need an absolutely accurate load forecast to operate the system and operate it economically,” he said.
Ganesh Velummylum, a senior manager of system analysis at NERC, placed the responsibility with transmission owners. He said they should ensure they have the necessary data before they agree to interconnect the resources.
“It starts with the TO,” he said. “Once we have the data, we can do studies. … We have to start with collecting the data through the interconnection process.”
Lack of data can create wider issues, as Boemer illustrated through what he called the “52-Hz problem” in Germany. Many DERs were programmed to trip off at frequency thresholds that are very close to normal frequency, which meant that small and normal frequency variations could cause widespread loss of DERs on the system.
It’s an issue PJM is currently looking at by increasing resources’ “ride-through” requirements. (See “Implementing DER Ride Through,” PJM Operating Committee Briefs: March 6, 2018.)
None of Germany’s transmission operators had modeled that problem in its studies, Boemer said. But the industry was able to identify the risk through published research and knowledge of system operations and operating standards. A catastrophic trip never occurred, but the German government set up a retrofit program to reprogram the trip settings for more than 400,000 distributed photovoltaic resources, he said.
Panelists also said DERs have the potential to benefit systems by addressing reliability issues and perform important grid services. In fact, the variability is useful, Bekkedahl said.
“What used to be very stable generation is moving on us,” he said. “Now that we’ve got variable generation going on, it’s really nice to have variable load.”
“The technology is there” to set up support for power, frequency ride-through and voltage support on the system, Velummylum said.
“They all interact,” he said. “I think it’s important that we look at the collective support DER can provide.”
DERs can also provide non-wires solutions, Bekkedahl said, noting their role in the cancellation of the Bonneville Power Administration’s I-5 Corridor Reinforcement Project. The 80-mile, $1.2 billion, 500-kV line would have helped Oregon utilities manage summer peaks when they were receiving no generation support from south of Portland.
“If Oregon was hot, California was hotter,” Bekkedahl said.
But subsequent DER development in California has changed the situation and eliminated the need for the transmission project. “Can we find non-wires solutions? I think absolutely,” he said.
Unlocking such solutions will require encouraging DERs to participate in wholesale markets so they are committed and required to provide information, Bielak said. “The only way you can determine if you can rely on them is with enough data,” he said.
FERC staff also asked panelists to discuss how to develop long-term projections, and many panelists looked to state policies because they drive development. Marcus Hawkins, the director of member services and advocacy for the Organization of MISO States, noted that a MISO study ended up relying on publicly available data because a voluntary survey of DER owners performed by a consultant received low participation.
“I think it starts with having a good understanding of the status quo” of what’s on the system today, Boemer said. He outlined “hosting capacity” studies that analyze distribution systems to identify potential thermal issues that could limit DER deployment on feeder lines. The analysis creates a heat map “that can indicate how much DER may be able to interconnect to certain areas on the distribution grid,” Boemer said.
The morning’s second panel focused on including DERs in system planning. Velummylum, who remained for the second panel, had a quick response. He held up two reliability guideline studies NERC has published that discuss DERs. “Folks, it’s out there,” he said.
Ning Kang, a staff scientist at Argonne National Laboratory, said the lab is working on improving its models through analysis it performed by studying smart inverter functions and focusing on how applicable standards impact performance.
Brant Werts, Duke Energy’s lead engineer for DER technical standards, said his company only considers the impact of losing DERs in specific areas. During the recent solar eclipse, he said the company lost a significant amount of DER but also knew it was coming and prepared for it. “We don’t believe that we would lose all of our DER at one time,” he said.
