PJM is experiencing an “unprecedented” switch from coal- to gas-fired generation while also managing the replacement of aging transmission infrastructure, staff concluded in the RTO’s annual transmission planning report.
The RTO received deactivation notices for 4,588 MW of generation in 2017, bringing the total since the end of 2011 to 34,967 MW. Deactivation requests in the eight years prior totaled 11,000 MW.
PJM greenlit $5.8 billion in transmission spending last year. That paid for 198 “baseline” projects to ensure compliance with NERC, regional and local transmission owner planning criteria, and 341 “network” projects to interconnect new generating stations. According to the RTO’s figures, that comes out to about $16 million per baseline project and about $8.6 million per network project.
On Feb. 14, PJM’s Board of Managers authorized another $397 million in transmission projects, dominated by TOs’ supplemental projects that are triggered by their own planning criteria. Transmission customers have complained about the uptick in such projects, which don’t require PJM board authorization but are included in the Regional Transmission Expansion Plan, because they believe TOs are using them to pad revenues. (See AMP Presses AEP, PSE&G on Transmission Projects.)
The recent approvals include two such efforts in the Public Service Electric and Gas and Dominion Energy territories. PSE&G plans to spend $115 million to construct a 230/69-kV substation with 69-kV ties to the Paramus and Dumont substations, and $98 million to convert the Kuller Road substation to 69/13 kV and construct a 69-kV network between the Kuller Road, Passaic, Paterson and Harvey stations. Dominion will replace existing infrastructure for a total of $50 million.
This chart shows how transmission projects approved over the past four years have transitioned from larger, “backbone”-type lines to smaller lines to address regional issues. | PJM
The remainder of the approvals consist of another Dominion project — $100 million to install three STATCOM dynamic reactive devices at two substations — and $29.5 million in spending spread across projects in the Baltimore Electric and Gas, PPL and Duke Energy Ohio/Kentucky territories.
Last month, FERC ordered PJM’s TOs to change their process for handling supplemental projects after finding the current approach does not comply with Order 890. TOs worked with PJM on the issue and last week proposed a plan to address the commission’s concerns (See related story, PJM, TOs Propose FERC Order 890 Compliance Plan.)
The PJM board has authorized $35.4 billion in transmission infrastructure spending since 1999. Baseline projects represent $27.9 billion of the total, with $7.2 billion authorized to interconnect 84,200 MW generation. Those figures include $181 million in cost overruns for 48 previously approved baseline projects and $540 million authorized for 336 network projects that were canceled after 257 generator interconnection requests were withdrawn, which reduced expenditures below authorized levels.
This chart shows how PJM expects the generation fleet to be transformed over the next five years. | PJM
But the numbers also provide some insight into development trends. PJM said the 2017 projects address market efficiency congestion and solve local reliability issues, and recent history shows a trend toward smaller lines rather than large, backbone-sized construction.
“Flat load growth, energy efficiency, generation shifts and aging infrastructure drivers — among others — continue to shift transmission need away from large-scale, cross-system backbone projects at 345 kV, 500 kV and 765 kV voltage levels,” the report states.
The generation interconnection queue is dominated by gas-fired facilities, and the deactivation list is littered with coal plants, but the fleet won’t be changing too much any time soon. PJM estimates that oil, wind, hydro and solar will all look about the same five years from now in 2023: slightly more than 10% of the total generation fleet.
Nuclear will drop slightly from somewhat less than 20% today to about 18% in 2023. Coal will also be down from around 31% today to about 28%. Gas increases significantly from roughly 40% today to more than 45%. PJM has said it can remain reliable with upward of 86% gas. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
FERC last week instituted proceedings to examine the reactive rate schedules of two MISO generating facilities: the 471-MW RockGen natural gas plant in Christiana, Wis., (ER13-1589) and the 555-MW Carville steam and gas cogeneration facility in southeastern Louisiana (ER18-554).
The commission opened a Section 206 proceeding in a new docket (EL18-51) to re-evaluate RockGen’s reactive rates as a result of parent company Calpine’s proposed acquisition by an investor group led by Energy Capital Partners. FERC had accepted RockGen’s $700,000 annual reactive service revenue requirement in 2013.
The owner of the Carville plant, LS Power Development, asked on Dec. 28 for an annual reactive power revenue requirement of more than $1.1 million.
FERC said Carville didn’t provide proper evidence for multiple factors behind its revenue requirement: “Several components of Carville’s revenue requirement are not adequately supported, including, but not limited to, Carville’s fixed [operations and maintenance] expenses included in the fixed charge rate, the Carville facility’s production plant cost components and the accessory electric equipment allocator. Additionally, Carville utilized an outdated federal tax rate and incorrectly applied … methodology in calculating the Carville facility’s balance of production plant cost,” the commission said in its Feb. 28 order.
LITTLE ROCK, Ark. — As the chair of SPP’s Regional State Committee in 2015, Oklahoma Corporation Commission (OCC) Chair Dana Murphy would, without fail, compliment her fellow committee members, regulatory and SPP staff, and other stakeholders for their efforts, no matter how small.
But that’s just Dana Murphy.
“I feel very grateful,” she said about her practice of recognizing others. “The thing is, there’s always going to be a healthy tension between regulators and SPP and the utilities, and I accept that. I accept that as part of the job, whether I’m serving as a commissioner in Oklahoma or representing Oklahoma here on the RSC.
“I don’t try to avoid [the tension]. The challenge with all of this — and it may be hard to believe — is that I’m an introvert who doesn’t like controversy. Yet, how did I get here?”
After serving on the OCC since 2008, and as its chair since February 2017, Murphy has set her sights on the lieutenant governor’s office.
She opened her campaign last July with a prayer in her hometown of Edmond. “I think all of you who know me know that my faith is the biggest part of pretty much everything I do beyond my family,” Murphy said.
Field of Four
Murphy is competing with three other Republicans — state Sen. Eddie Fields, former state party chair Matt Pinnell and “entrepreneurship consultant” Dominique DaMon Block Sr. — for the GOP’s slot in November’s statewide elections. The primary is June 26.
The commissioner has claimed a significant fundraising edge over her three primary opponents, finishing 2017 with $690,000 on hand after shifting nearly $639,000 from her OCC campaign account. Pinnell had $450,000 on hand, but outraised Murphy in the fourth quarter, $113,000 to her $44,000. Fields finished the year with $65,274 in funds; Block had nothing. Murphy’s donors include oil and gas executives, attorneys, insurance executives, lobbyists, real estate developers, bankers and real estate developers.
Murphy’s campaign website pledges “to address the roots of the longstanding problems facing our state, including the budget, education, health care and infrastructure,” but it is light on policy details.
Instead she highlights her Oklahoma roots and writes of putting more than 180,000 miles on her “little blue truck” to attend events statewide and “visit folks just like you.”
A fifth-generation Oklahoman, Murphy grew up on a ranch, graduated from Oklahoma State University with honors and first worked as a petroleum geologist. As Murphy says on her website, her family encouraged her to “do more and be more,” so she earned a night school law degree from Oklahoma City University while working as a law clerk.
The state’s Sooner Poll has yet to release results of the lieutenant governor’s race, but Pinnell appears to be her strongest opponent. Besides his fundraising prowess, he has built inroads with the national Republican Party by working as a campaign manager for the GOP in all 50 states.
Former Missouri Public Service Commissioner Steve Stoll, who served alongside Murphy on the RSC before cycling off the committee and his state’s commission in January, recalled her as “a very hard worker.”
“I know she cared deeply about the state and wanted to ensure her ratepayers were treated fairly,” he said.
“She has deep knowledge of the energy business, and energy is an integral component to the Oklahoma economy,” said SPP General Counsel Paul Suskie, who works closely with the RSC.
After six years as an administrative law judge for the OCC, Murphy won a seat on the commission in a 2008 special election. She was re-elected to full terms in 2010 and 2016 and has seen her workload grow from normal petroleum and electricity issues to ride-sharing companies and seismic activity related to fracking.
“To make really difficult decisions is something I’ve spent nine years on,” she said, referring to reaching consensus with the OCC’s other two commissioners, Vice Chair Todd Hiett and Bob Anthony. “We don’t have the same opinions on a lot of things, yet somehow, we have to find a way to work together to make decisions. You look at the stakeholders that we deal with, with very divergent opinions and decisions … you have to have the ability to try and process all that and make some really difficult decisions that ultimately, everyone is going to be unhappy with.”
Doing More with Less
Complicating matters, Murphy says, is that the OCC has been asked “to do more with less.”
“Our appropriations from the legislature continue to go down, but our authority and responsibility by statute have increased, just in the nine years I’ve been there,” she said.
Some Oklahoma utilities and petroleum companies have complained about the OCC’s delay in resolving rate cases, which has resulted in interim rates being implemented, subject to refund. Oklahoma law allows the commission to implement interim rates if the cases aren’t resolved in 180 days.
OGE Energy has led the complaints against the process, which reached a crescendo when its December 2015 request for $92.5 million was implemented on an interim basis of $69.5 million in the summer of 2016. The OCC gave OGE’s Oklahoma Gas & Electric utility customers a $47.5 million refund when the rate case eventually concluded last April.
“We are investing north of $500 million in our system every year. I think it’s my job to be supportive of the state, but we’ve got to be able to come up with a way to recover that in a timely manner,” OGE CEO Sean Trauschke said last month during the company’s most recent earnings call with analysts.
Oklahoma Gov. Mary Fallin (R) has responded to the outcry by forming a task force to suggest ways to improve the commission’s performance. (See OGE Anticipates Legislative Review of Oklahoma Regulators.) For her part, Murphy says she is hopeful the task force will increase awareness of the OCC’s challenges and responsibilities.
Lieutenant governor may not be Murphy’s ultimate goal. Oklahoma media note the position is seen as a stepping stone to the governor’s mansion. Case in point: Lt. Gov. Todd Lamb, an early frontrunner for this year’s GOP’s gubernatorial nomination, is now running second to Oklahoma City Mayor Mick Cornett in a crowded field. They are battling to replace the term-limited Fallin, who was elected governor in 2010 after previously serving as lieutenant governor and a U.S. representative.
Murphy, whose term ends in 2022, said she will continue to represent the OCC on the RSC and serve at the commission during her campaign for higher office. As she put it, “I’m here until I’m not here.”
FERC should stop issuing new cybersecurity standards to allow the electric industry to develop innovative defenses to vulnerable industrial control systems — and the National Guard should be ready to respond if an attack succeeds, witnesses told the Senate Energy and Natural Resources Committee on Thursday.
Walker
The panel heard from Assistant Energy Secretary Bruce Walker, a former National Security Agency cyber sleuth, the CEO of the National Rural Electric Cooperative Association (NRECA) and two academics in a nearly two-hour hearing. Chairman Lisa Murkowski (R-Alaska) opened the hearing by asking for advice on what Congress should do after giving FERC the power to issue mandatory reliability standards (in the Energy Policy Act of 2005) and making the Department of Energy the federal agency in charge of responding to attacks on the grid (in the 2015 Fixing America’s Surface Transportation Act).
Murkowski
Robert M. Lee, who founded industrial cybersecurity company Dragos with two other former NSA experts on industrial threats, told the committee that the critical infrastructure protection (CIP) standards mandated by FERC through NERC had made “the North American Bulk Electric System the most resilient and well defended in the world.”
But he said FERC and NERC should not issue any new CIP regulations for three to four years. “This would allow companies to catch up with the current regulations … [and] allow the electric asset owner and operator community to spend a period of time innovating and thinking of new best practices informed by experience. At the end of this period DOE, FERC, NERC and the regulated community can then identify best practices and determine if new regulations are appropriate,” he said.
Lee
“If this recommendation is not palatable, then I would propose an alternative where the regulations are focused instead on program building, such as regulating that a company implement a threat intelligence program, instead of performance-based auditing,” he continued. “This would satisfy the potential desire to move regulations forward while allowing the electric community to develop their own ways forward inside of those programmatic bounds.”
The problem, Lee said, is that “regulations and standards are the trailing end of best practices and only serve as a base level of security. They are not, nor would any regulation be, adequate in the face of determined adversaries. Malware and vulnerabilities are not the threat. The threat is the human adversary, and we cannot regulate them away.”
OT is not IT
Lee and other witnesses emphasized the differences between attacks on utilities’ information technology systems and those on operational technology systems such as supervisory control and data acquisition (SCADA).
Sanders
“Fortunately, the successful attacks to date have largely been concentrated on utility business systems, as opposed to monitoring and control systems, in part because the operational technology systems have fewer attack surfaces, fewer users with more limited privileges, greater use of encryption, and more use of analog technology,” said professor William H. Sanders, head of the Department of Electrical and Computer Engineering at the University of Illinois at Urbana-Champaign. “However, there is a substantial and growing risk of a successful breach of operational technology systems, and the potential impacts of such a breach could be significant.”
Walker, who heads DOE’s Office of Electricity Delivery and Energy Reliability, also made the distinction. “Power systems must operate continuously with high reliability and availability. Upgrades and patches can be difficult and time-consuming, with components dispersed over wide geographic regions,” he said. “Further, many assets are in publicly accessible areas where they can be subject to physical tampering. Real-time operations are imperative, and latency is unacceptable for many applications. Immediate emergency response capability is mandatory and active scanning of the network can be difficult.”
New DOE Cyber Office
Last month, DOE announced it was merging its Infrastructure Security and Energy Restoration (ISER) division and Cybersecurity and Emerging Threats Research and Development (CET R&D) division into the Office of Cybersecurity, Energy Security and Emergency Response (CESER).
Walker said CESER “will enable more coordinated preparedness and response to cyber and physical threats and natural disasters. This must include electricity delivery, oil and natural gas infrastructure, and all forms of generation.”
President Trump has requested $95 million in fiscal 2019 for the office “with a focus on early stage activities that improve cybersecurity and resilience to harden and evolve critical grid infrastructure,” Walker said. “These activities include early stage R&D at national laboratories to develop the next generation of cybersecurity control systems, components and devices including a greater ability to share time-critical data with industry to detect, prevent and recover from cyber events.”
Acts of War
Matheson
Jim Matheson, CEO of the National Rural Electric Cooperative Association (NRECA) and a former congressman (D-Utah), decried “far-fetched scenarios [and] sensationalized claims” about the risks to the grid.
“The scenarios most publicized are rarely reflective of the real threat environment and disproportionately emphasize the highest consequence scenarios that are the least likely to occur,” he said. “Many of the more dramatic scenarios would constitute acts of war on the United States and would directly impact more than just the electric sector.”
No Cyber Fire Departments
Endicott-Popovsky
Such an event would call for the National Guard, said Barbara Endicott-Popovsky, executive director of the Center for Information Assurance and Cybersecurity at the University of Washington.
Endicott-Popovsky said Congress should pass a bill that would establish National Guard Cyber Civil Support Teams of up to 10 members in every state and territory to serve as first responders following an attack and bridge the gap between federal and non-federal efforts. The cyber CSTs would be under the direction of governors and state adjutant generals, under legislation (H.R.3712) introduced last September in the House of Representatives and referred to the Subcommittee on Military Personnel in October. The bill is modeled after a program created by the Washington National Guard.
“Civilians are used to calling 911 for emergencies of all kinds, but who do you call in the event of a major cyber outage? There are no cyber fire departments,” she said. “The [Department of Defense] is prepared to defend their own networks to support their missions, but who will step in on the civilian and private sector sides to restore power, to assist with maintaining our communities? There is no one. This vacuum is a national security threat.
“Public and private, we have two very different missions: The mission of the military is to protect the Homeland, and the mission of private sector to innovate and maintain profitability for the board and shareholders,” she continued. “Blending missions is not an easy task, but the time has come where the cost of not integrating resources significantly outweighs the benefits of maintaining independent response plans. This is especially true given the workforce shortage of cyber specialists.”
Endicott-Popovsky said it will take a national effort comparable to NASA’s goal of landing on the moon to fill the shortage of cyber talent. “While cybersecurity education has been called a national priority by some, there still are hundreds of thousands of cybersecurity jobs going unfilled, and the gap will take a long time to close,” she said.
The good news: Cybersecurity is becoming a profession, with 32 distinct career paths identified under the National Initiative for Cybersecurity Education (NICE) framework, she said.
How Congress Can Help
In response to Murkowski’s question about Congress’ next steps, Matheson called for more timely information sharing by government after incidents such as the December 2015 attack on Ukraine’s grid.
He also called for legislation allowing the FBI to conduct background checks on utility industry personnel performing critical functions, continued funding for R&D and aid to small and medium utilities for improving their security.
Illinois’ Sanders said DOE, the Department of Homeland Security and researchers should focus their R&D and demonstration projects on developing six capabilities: “continuous data collection, fusion of sensor data, visualization, analytics, restoration and post-event tools.”
“These capabilities can be achieved only if academia, industry and government work closely together in a focused research and development program,” he said.
FERC on Wednesday accepted ISO-NE’s proposed new capacity bilateral transaction and a revised materiality threshold for determining whether a resource can satisfy its capacity supply obligation (CSO) (ER18-455).
The grid operator proposed the annual reconfiguration transaction (ART) to replace the capacity market’s existing bilateral contracting mechanism, the CSO bilateral. The RTO said the change was needed to accommodate its transition to marginal reliability impact-based demand curves (MRI), which are based on the expected improvement in reliability from adding incremental capacity.
The commission’s Feb. 28 order said that the ART will give resources looking to replace their CSO through a bilateral contract more flexibility. “The ART mechanism will accommodate even or uneven exchanges within the same zone or across constrained zone boundaries, even where exchanges previously were prohibited, while accounting for the actual net impact on reliability in a manner that does not disadvantage suppliers or consumers,” the commission said.
| Energyzt, ISO-NE
FERC also agreed to ISO-NE’s proposal to change how it determines when to submit demand bids in the third Annual Reconfiguration Auction (ARA) for resources that have a significant decrease in capacity. The RTO said its previous threshold — 20% of its CSO or 40 MW, whichever is lower — produced outcomes that focus on relatively small deficiencies and ignore relatively large deficiencies. For example, a 35-MW deficiency from a 100-MW resource would be subject to the RTO’s mandatory demand bid rule, while the same deficiency from a 200-MW resource would be exempt.
Under the new rules, the RTO will intervene when a resource’s capacity decreases by 10 MW, or 10% (but at least 2 MW), whichever is lower.
The commission dismissed FirstLight Power Resources’ request to eliminate the minimum 2-MW floor for the threshold. “We do not find any evidence that the proposed changes will result in undue discrimination among resources or compromise the integrity of the capacity markets, as FirstLight claims,” it said. The proposed thresholds “reasonably balance the impact on large and small resources, while reducing ISO-NE’s administrative burden.”
FERC also rejected a request from New England generators Exelon, CPV Towantic and NRG Power Marketing that the mandatory demand bid changes take effect in Forward Capacity Auction 9, rather than FCA 11.
| Energyzt, ISO-NE
Because it found the “proposal, including its implementation date, to be just and reasonable, we need not consider whether an alternative proposal is also just and reasonable,” the commission said.
There was no evidence that the new threshold will undermine the integrity of the capacity market, the commission said. “For all resources, regardless of the significant decrease threshold, the general obligations associated with having a CSO continue to apply.” The existing thresholds have not undermined the integrity of the capacity market or sent a signal that it is appropriate to intentionally overstate a resource’s capacity values, it said.
“We find it is reasonable to expect that the revised rules, which ISO-NE expects to affect a similar amount of capacity as the existing rules, likewise would not undermine the integrity of the market,” the commission said.
FERC last week rejected the New York Public Service Commission’s request to rehear a November 2017 decision granting NextEra Energy Transmission New York (NEET NY) a 50-basis-point adder for participating in NYISO.
The ISO in October selected the company’s Empire State Line proposal to address a need for new transmission in western New York.
Empire State Transmission Line | NextEra Energy Transmission
FERC’s Feb. 28 order dismissed the PSC’s argument that a participation adder — or membership incentive — was unnecessary because NYISO selected NextEra as part of its transmission planning process, leaving the company no choice but to turn over operational control of its transmission to the ISO (ER16-2719).
The federal commission countered that the incentive recognizes the consumer benefits, including reliability and cost benefits, that flow from ISO membership.
Section 219 of the Federal Power Act provides for incentives to each transmitting utility or electric utility that joins an RTO/ISO, and incentive-based rate treatments benefit consumers by ensuring reliability and reducing the cost of delivered power, FERC said.
Empire State Transmission Line | NextEra Energy Transmission
“We consider an inducement for utilities to join, and remain in, transmission organizations to be entirely consistent with those purposes … and the best way to ensure those benefits are spread to as many consumers as possible is to provide an incentive that is widely available to member utilities … and is effective for the entire duration of a utility’s membership in the transmission organization,” FERC said.
FERC granted NEET NY’s request subject to the return on equity with the adder being within the zone of reasonableness, it noted.
SAN DIEGO — A joint effort between Peak Reliability and PJM offers Western industry players a chance to design their own market, one that will operate with more transparency than CAISO, PJM CEO Andy Ott said last week.
“The whole key here is the ability of the West to build up its own rules,” Ott said.
The CEO added that PJM’s expertise in coordinating markets and dealing with regional differences in the East will be a major asset in developing a Western market in partnership with Peak.
Having traveled west last week to attend a meeting of the Western Power Trading Forum, Ott sat down with RTO Insider to discuss the new Peak Reliability/PJM Connext market proposal. (See Peak Touts ‘Independent’ Western Market Plan.)
The partnership is galvanizing interest across the industry around a new Western market, but it comes amidst several other major recent developments shaking up the region.
Among them: competing efforts by CAISO to provide reliability coordinator (RC) services and extend its day-ahead capability into the Energy Imbalance Market (EIM). (See CAISO Plan Extends Day-Ahead Market to EIM.)
PJM’s executive spoke frankly about the shortcomings he sees in CAISO, including what he characterized as a relatively closed-door process for addressing market issues, compared with the more stakeholder-driven approach he envisions for the Peak market.
In California, “they have a discussion about a specific issue they are going to change, then they go in a room and make a decision, and they come out and they have a decision,” Ott said. “It’s not done that way everywhere.”
Ott touted PJM’s experience in operating a 13-state, multibillion-dollar energy market in the East. The RTO brings that experience to the effort, while Peak has the real-time reliability model of its territory already completed, he said.
Aside from the market proposals, Peak and CAISO are competing to provide NERC-certified RC services. Shortly after Peak and PJM announced their effort, CAISO dropped Peak as its RC and announced it would offer Western utilities RC services at a lower cost.
Peak CEO Marie Jordan, who also attended the WPTF event, noted that the only non-revocable notice of departure that the organization has received so far is from CAISO. Several Peak customers have announced they will leave, after CAISO issued its notice of withdrawal at the beginning of the year.
Late last month, the Bonneville Power Administration and Western Area Power Administration separately announced they have signed nonbinding notices signaling their intent to depart Peak by the end of 2019. BPA said it is exploring receiving RC services from CAISO, while WAPA is considering SPP and CAISO for some of its balancing authorities.
A business plan for the Peak Reliability/PJM Connext proposal is due at the end of March
Ott noted that the EIM was designed with the specific purpose of giving California a way to export renewable generation and get services back. The market benefits California customers, and he called outside regional participants “guests” in the market.
“I see the EIM, frankly, as a stopgap,” Ott said. “It was created to solve a problem.”
Ott said the business case for the market is being studied and is due to be issued March 30. Peak executives have publicly discussed the potential for the effort to evolve into a full RTO, something Ott says will depend on input from market participants.
“Our mindset is that if we put the PJM name on something, it’s not going to fail. We cannot afford to let it fail,” Ott said.
PJM and its transmission owners released a joint proposal last week to address FERC’s decision last month that the TOs are not in compliance with Order 890 (EL16-71, ER17-179).
The commission ruled that the TOs were failing to provide stakeholders with adequate notification, information and enough opportunities to engage on “supplemental” projects —transmission expansions or enhancements not required for compliance with reliability, operational performance or economic criteria. The projects are part of PJM’s Regional Transmission Expansion Plan but not subject to staff’s oversight and approval. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
FERC ordered the TOs to define nine time-period minimums that were previously vague. In response, TOs have proposed there be a minimum of 25 days between meetings on the three parts of project planning: assumptions, needs and solutions. They also offered to post information to be discussed at that meeting 10 days ahead of time and allow 10 days after meetings to receive comments. Finally, they proposed a 10-day waiting period to consider written comments before incorporating their local transmission plans into the RTEP.
“The minimum time periods proposed are designed to complete the consideration of supplemental projects in time for the PJM board meeting to approve the Regional Transmission Expansion Plan in July and in subsequent RTEP approval cycles throughout the year,” PJM and the TOs wrote in the joint proposal.
PJM is giving stakeholders until March 9 to comment on the proposal. But some have already said they aren’t yet ready to sign off.
“We are carefully reviewing the filing with a view of the current planning process as well as the language in the order,” said American Municipal Power’s Ed Tatum, who has been a vocal critic of the process. “Absent discussion with the TOs, PJM and other stakeholders, it is difficult to determine if the time frames and process proposed will yield any improvement to the current process.”
NEW CASTLE, N.H. — More than 100 people gathered with ISO-NE’s Consumer Liaison Group (CLG) at the historic Wentworth by the Sea hotel to discuss the rapid changes overtaking New England’s electricity market.
The CLG holds quarterly meetings around the region to provide a chance for residents, state officials and energy experts to learn more about the grid operator.
CLG Chair Rebecca Tepper, chief of the energy and telecommunications division in the Massachusetts attorney general’s office, said the group is “thinking about additional opportunities for members of the CLG to talk directly to ISO New England professionals and staff, just so there’s more direct communication available.”
Here’s more of what we heard at the CLG’s most recent meeting.
New Hampshire Public Utilities Commissioner Michael Giaimo said that New England’s market restructuring has benefited consumers.
“No longer can a utility build a generation facility solely on the backs of ratepayers,” Giaimo said. “The system of captive ratepayers being susceptible to stranded costs has been replaced by developers and their shareholders bearing the risks and the rewards associated with building, operating and maintaining a generation facility.”
Anne George, ISO-NE vice president for external affairs, said the RTO’s 2017 average wholesale energy prices were the second lowest since 2003, while last month’s Forward Capacity Auction 12 marked the third consecutive decline in clearing prices. (See ISO-NE Capacity Prices Hit 5-Year Low.)
George reiterated the RTO’s concerns about fuel security, a challenge brought home during two bitter cold weeks around New Year’s Day when New England generators burned through nearly 2 million barrels of oil, more than twice the amount used by the region’s power plants during all of 2016. (See Van Welie: ISO-NE in ‘Race’ to Replace Retirements.)
Giaimo noted that the cold snap saw the value of the region’s energy transactions surge to about $1.1 billion during the first three weeks of January, equal to 25% of the entire energy market value in 2015. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
Markets Misalignment
Jonathan Peress, director of energy market policy at the Environmental Defense Fund, said the Northeastern power price spike observed Jan. 5 was not driven by New England gas pipeline constraints but by New York City power demand, which was symptomatic of a misalignment between gas and electric pricing.
“Very high LNG sendout kept Algonquin [gas hub] prices lower than would otherwise have been the case on Jan. 5,” Peress said. “LNG was the key resource that allowed consistent access to gas.”
The value of gas supply and pipeline delivery service fluctuates over the course of the day, but the gas market primarily relies on a single daily index price. Non-ratable takes are valuable to generators, but the variable flow and pipeline flexibility service is not priced, he said.
“It’s really not good to be relying on 50-year-old oil steam boilers for our reliability in New England,” Peress said. “I used to manage some of them — not pretty.”
New Hampshire Sen. Andy Sanborn (R) said “virtually every woe you have, when it comes to your ability to run your company and energy policy, actually solely starts at the legislature.”
The legislature controls the energy conversation, and discussion ends up being a debate between left and right, Sanborn said, when the region has systemic problems.
“It is specifically the legislature that determines whether we’re going to let that market run freely, all the way from our ability to sign off on long-term plan purchase contracts … to what percentage of our business needs to be renewable or non-renewable, and whether or not we are allowing companies to bring gas in or bring power down,” Sanborn said.
Market-Based Solutions
Carl Gustin, a communications strategist with consultancy Salient Point, brought a historical perspective to the discussion by recalling how the 1978 Power Plant and Industrial Fuel Use Act banned the use of natural gas by power plants.
The first energy-efficiency measures elicited disbelief among utility executives who could not envision “un-selling” their product.
“We called it conservation back then,” Gustin said.
But now: “You’ve got renewables coming up and coming on quickly and you’ve got to manage that system both for voltage and for reliability,” Gustin said. “You’ve got a big problem in front of you.”
Tanya Bodell, executive director of consultancy Energyzt, said that, coming from the Chicago school of economics, she always favors market-based solutions.
“Right now, there’s not an incentive through the price signal for most customers to adjust their consumption, so we’re really not tapping into the demand response,” Bodell said. “And customers can make money — those who are able to make those adjustments. I would say that’s a market solution.”
Pricing carbon is another market-based solution, she said.
“If you put a price on carbon, the cost of the oil-fueled units will become more expensive and other alternatives, LNG for example, can come in and help to solve that. We saw LNG flowing into New York. If the price signal is there, it will come.”
FERC on Wednesday approved the proposed $14 billion merger between Great Plains Energy and Westar Energy, ruling that it would not have an adverse impact on market competition or rates in SPP.
The deal is still subject to approval by Kansas and Missouri regulators.
Missouri-based Great Plains owns Kansas City Power & Light, and Kansas-based Westar owns Kansas Gas and Electric. Kansas regulators last year pushed back on Great Plains’ original plan to buy out Westar, spurring the companies to recast the transaction as a “merger of equals.”
Under a revised plan filed with the Kansas Corporation Commission in late August, Great Plains proposed that the two companies would combine under a $14 billion holding company operating in both Kansas and Missouri. Westar shareholders would own about 52.5% of the company with Great Plains shareholders holding the rest, according to the amended merger application (18-KCPE-095-MER). The companies have pledged that the holding company will maintain separate debt and capital structures for each subsidiary. (See Great Plains, Westar File Revised Merger Plan.)
The deal would entail no cash exchange or transaction debt, and retail customers would receive $50 million in upfront bill credits across all rate jurisdictions. The combined company would serve about 1 million customers in Kansas and almost 600,000 customers in Missouri.
In approving the deal, FERC made clear that a five-year hold-harmless commitment agreed to by the two companies would not cover any costs related to Great Plains’ failed bid to buy out Westar (EC17-171). Under that commitment, Great Plains and Westar have agreed not to seek to recover any costs related to integrating the companies unless they can demonstrate, through a Section 205 filing, that a merger activity yielded savings in excess of costs incurred.
| Great Plains and Westar
But the commission clarified that because Great Plains’ original acquisition strategy was “pursued but never completed,” costs related to the transaction “should not be included as part of the hold-harmless commitment and cannot be recovered from ratepayers pursuant to it. The costs related to the 2016 transaction are instead subject to the commission’s ordinary ratemaking principles under [Federal Power Act] Sections 205 and 206.”
Additionally, FERC said it was not persuaded by a protest by Kansas Electric Power Cooperative, which asked the commission to apply an equally strong hold-harmless commitment to wholesale customers as it would for retail customers, using pre-merger common equity levels to calculate rates, shielding the co-op from merger-based rate impacts. It also asked that all hold-harmless commitments be indefinite.
FERC said ordering extra hold-harmless protections without evidence would be “speculative” and noted that it doesn’t require merger plans to include hold-harmless commitments for market-based wholesale power sales.
The commission also declined the co-op’s request that Great Plains and Westar provide it with a detailed list of all merger-related costs through a new compliance filing.
The proposed merger is still in prehearing stages at the KCC until March 19, when the first evidentiary hearing is scheduled. A public comment period on the merger ends March 29.
The Missouri Public Service Commission is also reviewing the proposed merger and will hold evidentiary hearings March 12 to 16 (EM-2018-0012).
