SPP’s energy prices and average hourly load this summer were below 2018 levels, while generator outages and congestion both increased, the RTO’s Market Monitoring Unit said in a recent report.
The MMU’s quarterly market report for the summer months (June-August) showed the average day-ahead price was $23.02/MWh and the average real-time price was $22.32/MWh during the period, a 10% decrease from the previous summer’s prices. The $1.54/MMBtu average gas price at the Panhandle Eastern pipeline was a 35% drop from the 2018 summer average of $2.35/MMBtu.
Prices were highest in the southeast portion of SPP’s footprint, northwest Kansas and South Dakota. Prices were lowest around the Kansas-Oklahoma border and in the northwest region of the footprint.
At the same time, the average hourly load was down 3% to nearly 35 GWh, from just under 36 GWh in 2018. Cooling degree days, used to estimate the effect of actual weather conditions on energy consumption, fell 9% from 2018 to 2019.
The MMU devoted the report’s “special issues” section to the continued increase in generation outages. SPP saw a monthly average of 26,000 GWh in total generation outages this summer, a marked increase from just two years ago, when outages averaged around 17,000 GWh.
“A central tenet of SPP is that ‘reliability and economics are inseparable,’” the Monitor said. “Economic incentives should drive behavior that increases reliability. However, circumstances exist that are not promoting reliability through economic incentives.”
The report focuses on maintenance outages for the first eight months of the year, which increased from 35,000 GWh in 2017 to 45,000 GWh in 2019. Maintenance outages are generally taking longer than previously, which indicates there may not be as much incentive as before to quickly complete maintenance outages, the MMU said. With low gas prices, “it has been necessary for gas resources to take outages to perform maintenance previously completed when the resource was offline,” the Monitor said.
Congestion was up during the summer, with 35% of all pricing intervals showing a breach in which the load on a flowgate exceeds the effective limit. Load-serving entities earned $80 million in congestion payments and were able to fully cover their $70 million in congestion costs through the congestion-hedging market.
Coal-fired resources’ percentage of total generation continued to fall, down from 50% in summer 2017 to 36% this summer. The increase of wind generation and gas generation (because of low gas prices) has made up the difference.
The MMU has scheduled a web conference for Nov. 8 at 2 p.m. to discuss the report.
SACRAMENTO, Calif. — More elected officials are calling for a public takeover of Pacific Gas and Electric or a government restructuring of the utility after it blacked out millions of Californians to prevent deadly wildfires sparked by its equipment.
Gov. Gavin Newsom summoned PG&E executives and creditors to his office Tuesday to try to resolve the battle between Wall Street hedge funds for control of the bankrupt company. A spokesman said Newsom told PG&E CEO Bill Johnson in the closed-door session unless the situation changes, the state will step in.
Newsom told U.S. Bankruptcy Judge Dennis Montali much the same thing in a letter Friday.
“It is my hope that the stakeholders in PG&E will put parochial interests aside and reach a negotiated resolution in the near term,” Newsom wrote to Montali, who is overseeing the utility’s Chapter 11 case in San Francisco. “If the parties fail to reach an agreement quickly to begin this process of transformation, the state will intervene to restructure the utility.”
Thousands of firefighters have battled blazes sparked by PG&E equipment. | Cal Fire
On Monday, a coalition of California mayors and county supervisors wrote a letter to the California Public Utilities Commission and Newsom arguing PG&E should be transformed into a public cooperative to fix the operational and governance problems that have plagued it for years and to ensure it emerges from bankruptcy as a “viable, credit-worthy entity.”
“In a growing coalition of local community leaders, we are developing a proposed structural change for PG&E that addresses all three of these key elements,” it said. “Based on a foundation currently in the Public Utilities Code, we will propose transforming PG&E into a mutual benefit corporation — in essence, a cooperative owned by its customers.”
The battle between PG&E’s bondholders and shareholders playing out in the bankruptcy court is “merely spectacle, without regard for what will be left behind when the financial players inevitably leave the scene,” it said. (See Attorneys Clash over PG&E Reorg, Blackouts Resume.)
Billions of dollars in government bonds could help harden PG&E’s grid against wildfires, the officials argued.
The letter was signed by the mayors of 16 cities — including San Jose Mayor Sam Liccardo, who initially proposed the plan — and supervisors from five counties in Central and Northern California.
Sacramento Mayor Darrell Steinberg signed the letter, though his city is already served by the Sacramento Municipal Utility District (SMUD), which began its efforts to purchase PG&E’s local electrical system in 1923 and finally succeeded after more than 20 years of legal wrangling.
SMUD is now the nation’s sixth-largest community-owned nonprofit electric utility. Its service territory, surrounded by PG&E’s, has avoided many of the problems that have plagued PG&E, including the large-scale blackouts of recent weeks.
“I signed the letter out of solidarity with my fellow mayors,” Steinberg said in a statement. “Here in Sacramento, we’re fortunate to be served by SMUD, our municipal utility, and we haven’t experienced the blackouts or other problems like those happening in PG&E’s territory. Electricity is a life-or-death commodity and should be viewed as a public resource.”
PG&E Responds
On a sidewalk near the state Capitol, PG&E CEO Johnson said he understood the urgency of the situation and why the governor had called for a brokered solution.
“We have to emerge from bankruptcy and then we have to become the utility of the future,” the former head of the Tennessee Valley Authority told reporters. But he said making PG&E a public utility could burden ratepayers with expenses they don’t pay now.
“I think it has the potential to inadvertently shift costs,” he said. “I think the way it’s structured now is the best idea for the majority of customers.”
PG&E serves a 70,000-square-mile area of California, including San Francisco and San Jose. | California Energy Commission
Regarding the recent public safety power shutoffs, which blacked out more than 2 million people twice in one week, Johnson said PG&E’s decisions had saved lives as the region faced high fire danger from unusually dry and windy conditions. The company’s equipment came under suspicion, however, for starting the 78,000-acre Kincade Fire on Oct. 23 in Sonoma County. (See PG&E Stock Plummets amid Wildfires, Shutoffs.)
This Friday marks the one-year anniversary of the Camp Fire, which killed 86 people and leveled the town of Paradise. PG&E equipment sparked that fire, state investigators found. The California Department of Forestry and Fire Protection (Cal Fire) also blamed PG&E equipment for starting 21 of the wine country fires of October 2017, which combined killed 20 people.
“I came to California with one basic purpose,” Johnson said. “Let’s make sure we don’t kill anybody in our operations. And I think we achieved that this year. I understand the hardship. I apologize for it. But for me, safety has to come first.”
PG&E responded to the governor’s ultimatum and the mayors’ takeover bid in written statements.
“We share the Governor’s focus on reducing wildfire risk across California and understand PG&E must play a role in these efforts,” the utility said. “We welcome the Governor’s and the State’s engagement on these vital matters and share the same goal of fairly resolving the wildfire claims and exiting the Chapter 11 process as quickly as possible.”
PG&E’s reaction to the mayors’ proposal was more dismissive, echoing statements it made earlier this year when it rejected San Francisco’s $2.5 billion offer to buy PG&E’s grid in the city. (San Francisco’s mayor did not sign Monday’s letter, but the city has said it still wants to create a municipal utility.)
“We are aware of proposals by various government agencies to acquire PG&E assets or to convert parts of the company to what is being described as a mutualized entity,” PG&E said. “We study and analyze each proposal. However, PG&E’s facilities are not for sale, and changing the structure of the company would not create a safer operation.”
“We remain firmly convinced a government or customer takeover is not the optimal solution that will address the challenges and serve the long-run interests of all customers in the communities we serve,” it said.
BALTIMORE — State officials from PJM’s western and southern borders last week expressed concerns about their autonomy after resuming a long-standing debate about whether states should strengthen their collective role within the RTO.
Panelists at the Organization of PJM States, Inc.’s annual meeting gave varying accounts of how the RTO’s structure benefits them, with many regulators in the west and south vocalizing concerns about the future of PJM’s markets and its impacts on their ratepayers.
“My fear is we are moving very far down a path where organizations like PJM are too big to fail,” said Charlotte Lane, chairman of the West Virginia Public Service Commission. “They are becoming unregulated fiefdoms.”
Lane said states should maintain control of their resources, particularly given the potentially skewed impacts of policies on carbon pricing and other market rules PJM will attempt to accommodate in the coming years. She also described “the constant bickering over market rules that are thinly-veiled attacks on some types of generation over others” as one of the more disturbing elements of RTO involvement.
“I believe states must remain in control of their resources. That is and should remain our individual right,” she said. “Though we are diverse in our views, I believe OPSI states have a mutual interest in maintaining that individual control.”
Charlotte Mitchell, chair of the North Carolina Utilities Commission, said she’s concerned about potential “erosion” of jurisdiction and characterized her impression of PJM’s relationship with states as “adversarial.” Dominion Energy serves 125,000 customers in the northeastern corner of North Carolina, the only area of the state within PJM’s footprint.
“We certainly want to maintain our authority over the resource planning Dominion undertakes, but we will look to PJM to continue to provide adequate, affordable and reliable service,” Mitchell said.
Kentucky, too, grapples with its autonomy in an RTO that’s racing toward clean energy at breakneck pace, said state Secretary of Environment and Energy Charles Snavely on an OPSI panel about carbon pricing. He said Kentucky won’t shutter coal plants early just to appease renewable energy targets in the east and contended the state will leave PJM to protect its economy from increasing electricity rates, if forced to. (See Enviro Officials Talk Carbon, Consequences at OPSI.)
“It is our opinion that PJM is enabling the policies of certain states at the expense of others,” he said. “We will reconsider our participation in PJM just out of necessity. It appears to me a lot of this is a competitive move by some of our members to further their economic interests, and Kentucky will further our own interests too.”
‘A Tool, Not an Outcome’
Marji Philips, of LS Power, challenged the panelists on their criticisms of PJM’s structure, noting it’s produced an “enormous amount of efficiencies” that benefit their ratepayers.
“PJM is a tool, not an outcome,” she said. “You all want to take back control of your resources but lean on the [power] pool when you can’t do it. When you take it all back, they [PJM] can’t do their job.”
The sentiments speak to a larger debate about whether PJM states should pursue a more involved governance role. Unlike states in other RTOs, OPSI members can’t assist in choosing the RTO’s board members, vote on proposed market rules or file alternative plans at FERC. A report authored by former state commissioners turned clean energy consultants called “Making Markets Work for PJM States” suggested changing those rules — as well as giving states the power to set their own capacity reserve targets or adopting a fixed resource requirement option — could prove beneficial.
OPSI itself takes no position on the report and said it was only used to stimulate discussion for the governance panel at its annual meeting last month.
“At such time that OPSI develops a position or wishes to recommend changes to PJM, those thoughts will be communicated to PJM in writing with an indication of the degree of support within the organization for the proposal,” OPSI Executive Director Gregory Carmean told RTO Insider in an email on Tuesday.
However, building upon the existing benefits of participating in an RTO mattered most for some panelists — like Michigan Public Service Commissioner Tremaine Phillips, who said a recent polar vortex and several corresponding electrical emergencies underscored the value of PJM in times of need.
But the cold weather snap across the Midwest in late January and early February also pointed to deficiencies in Michigan’s import capacity and its visibility of distributed energy resources in PJM, he said.
“It’s more an issue of with these low-probability, high-impact events and the probability of these events given the capacity and generation mix,” he said. “Those are real situations we have to continuously look into and evaluate. When those instances occur, we have to rely on our neighbors for assistance. Those issues have to be discussed RTO-wide to ensure those resources are available when we need them.”
Judith Jagdmann, chairman of the Virginia State Corporation Commission, said PJM has done a good job of providing reliability at a low cost and it’s up to states to make sure their participation continues providing value to its ratepayers.
“What I see … is that each PJM member is going to have to decide what is enough of a win for you to stay in PJM,” she said. “We can’t all have everything we want.”
The New England Power Pool Participants Committee on Friday approved ISO-NE’s proposed installed capacity requirement (ICR) calculations for Forward Capacity Auction 14 (2023/24) and three annual reconfiguration auctions (ARAs), to be conducted in 2020.
The PC followed the Reliability Committee in reversing its earlier rejection of net ICRs of 32,205 MW for 2020/21 ARA 3, 32,230 MW for 2021/22 ARA 2 and 32,465 MW for 2022/23 ARA 1, with 61.71% in favor. (See NEPOOL Reliability Committee Briefs: Oct. 23, 2019.)
The Generation sector unanimously opposed the ICRs, but they had the support of the other sectors, including Transmission (16.79%), Supplier (3.36%), Alternative Resources (10.38%), Publicly Owned Entity (16.79%) and End User (14.39%).
The committee also narrowly approved, with 60.04% in favor to meet the minimum 60%, a 940-MW value for the Hydro-Québec interconnection capability credit (HQICC) for FCA 14’s ARA 3, with the value rising to 958 MW for ARA 2 and 969 MW for ARA 1.
The Generation sector also unanimously opposed the HQICC motion, but the other sectors supported, including Transmission (16.79%), Supplier (1.68%), Alternative Resources (10.38%), Publicly Owned Entity (16.79%) and End User (14.4%).
ISO-NE plans to file the ICR values with FERC on Tuesday.
2019 system operations – load forecast accuracy | ISO-NE
No Recovering IROL Costs
The PC failed to support the Schedule 17 cost recovery provisions as proposed by ISO-NE to compensate certain generators and transmission facilities for incremental costs related to interconnection reliability operating limits (IROL) and critical infrastructure protection.
The motion failed to pass, with 63.84% in favor, just short of the necessary two-thirds. The Transmission and End User sectors were unanimous in opposition, while the other sectors supported, including Generation (16.79%), Supplier (15.86%), Alternative Resources (14.4%) and Publicly Owned Entity (16.79%).
These incremental costs cannot now be competitively offered and recovered through the energy and capacity markets.
An IROL is an operating limit that, if exceeded, could lead to a significant adverse reliability impact on the New England system, as well as neighboring systems to the west and north, according to a background memo from ISO-NE analyst Jon Lowell.
The reliability impact could be loss of significant portions of the New England system — and neighboring systems — because of system instability, cascading outages or uncontrolled system separation.
Generators and transmission facilities designated by the RTO as critical to the determination of IROLs must meet higher NERC CIP standards because their loss or misuse could have an adverse impact on the reliable operation of the grid, including instability in the bulk electric system, the memo said.
Energy Market in October down 61% Y-o-Y
ISO-NE CEO Gordon van Welie did not appear before the committee, though he did attend various meetings earlier in the day between market participants, the RTO’s Board of Directors and officials from the six New England states.
COO Vamsi Chadalavada reported that prices in the region’s energy markets have been hitting historic lows, with the market value for October at $151 million, down $60 million from September 2019 and $238 million from the same month a year ago.
Average natural gas prices and real-time hub LMPs over the period were down 51% and 46%, respectively, from October 2018.
Average day-ahead cleared physical energy during peak hours as a percentage of forecasted load was 98.9% through Oct. 23, down from 99.5% during September.
Daily average day-ahead and real-time ISO-NE hub prices and input fuel prices: Oct. 1-23 | ISO-NE
Financial Assurance Policy Changes
The PC approved changes to the RTO’s Financial Assurance Policy (FAP) related to financial assurance requirements for non-commercial resources in the Forward Capacity Market, but it rejected changes to the rate used to calculate the FAP for non-commercial capacity.
According to a memo from NEPOOL counsel Paul Belval, the RTO said the proposed change would remove the profit motivation for resources not expected to deliver because such profits would be offset by a proportionate increase in collateral requirements until the project achieves commercial operation.
The change does not collateralize any capacity supply obligation that originates outside of the FCA, consistent with the existing design.
The committee rejected basing the rate used to calculate non-commercial financial assurance on the net cost of new entry value in place for the given FCA, rather than the current practice of using the FCA clearing price.
The motion failed to pass the two-thirds needed with a 61.47% vote in favor.
ISO-NE this week will inform market participants what it plans to do with the split decision.
NEPOOL rules prohibit RTO Insider from quoting stakeholders’ comments during the meeting. However, Brett Kruse, vice president of market design at Calpine, confirmed after the meeting that, for example, in FCA 10, New England saw 900 MW of so-called phantom capacity that bid into the market, cleared and then never showed up in the operating year.
“This region performs exponentially worse than other forward capacity markets for what is supposed to be a physical resource,” Kruse said.
Consent Agenda
The committee unanimously approved, with abstentions noted, four items on the consent agenda. The first three were approved by the RC and the last by the Transmission Committee:
Revisions to Operating Procedure 16J, to modify the timing for initiating the annual certification of transmission equipment dynamics data;
Revisions to Operating Procedure 2A, to modify the table of itemized equipment maintenance of communications, computers, metering and building services;
Revisions to Planning Procedure No. 10, to delete provisions related to interconnection service adjustments that are being incorporated into the Tariff; and
Tariff revisions (including Section II.48 and Schedules 22, 23 and 25) to clarify interconnection service adjustments.
The committee also approved in a single vote, with one abstention, two other items that did not make it on the consent agenda because of lack of time:
Revisions to OP-16 Appendix J, to clarify the requirements for the annual certification of transmission equipment dynamics data and incorporate additional clarity; and
Revisions to OP-2 Appendix A, to add certain equipment and technology, and delete obsolete language.
Litigation Report
NEPOOL Secretary David Doot, a Day Pitney attorney, highlighted two items from the monthly litigation reports, including a FERC investigation into Order 1000 exemptions for “immediate-need” reliability transmission projects, which will be discussed in detail at the next TC meeting, Dec. 17 (EL19-90).
The second item concerned an appeal pending of the commission’s notice of inability to act for lack of a quorum on the RTO’s inventoried energy program proposal, which became effective “by operation of law” in September, as did the latest FCA results. (See FCA 13 Results Stand Without FERC Quorum.)
Several New England municipal utilities and Energy New England last week petitioned the D.C. Circuit Court of Appeals to rule on the matter (ER19-1428).
The American Wind Energy Association last week announced a major milestone for U.S. wind energy, saying there are now more than 100 GW of wind farms operating in the country.
That is enough energy to power 32 million American homes, AWEA CEO Tom Kiernan said during a media briefing Oct. 31.
Put another way, he said, it’s enough energy to power California and New Jersey for a year.
“It’s an extraordinary milestone,” Kiernan said. “It’s an extraordinary journey the industry has gone through, and it sets the stage for the journey ahead of us.”
According to AWEA’s third-quarter report, the U.S. now has 100,125 MW of wind capacity, with more than 57,700 wind turbines in operation across 41 states and two U.S. territories. Developers installed eight new wind projects, with a capacity of 1,927 MW, during the quarter. They have brought 3,667 MW online so far this year, a 123% increase over the first three quarters of 2018.
Texas leads the way with 2,129 MW of capacity in 2019, followed by Iowa (536 MW) and Kansas (475 MW).
Kiernan noted the industry’s exponential growth. He said it took 28 years to build the first 25 GW of wind energy but only 11 years to get the next 75 GW into the ground.
AWEA said 22.6 GW of wind projects are under construction and an additional 23.8 GW are in advanced development. The 46.4-GW total is almost half the wind energy operating today.
The development pipeline includes 5,792 MW of offshore wind, which Kiernan said is “similarly taking off [like traditional wind farms], and arguably at a faster clip and exponential growth.”
U.S. annual and cumulative wind power capacity growth | AWEA
New York has selected 1,696 MW from two projects to help meet its goal of 9,000 MW of offshore wind by 2035. Virginia Gov. Ralph Northam issued an executive order for the state to develop 2,500 MW of offshore wind by 2026.
Keirnan said he believes the industry has a “good shot” at a tax credit for wind energy and tax extenders for onshore wind.
“Things are moving forward,” he said. “We do anticipate significant further discussion [on legislation] this fall, but again, significant uncertainty. How we get from here to the end of the year is a significant to-be-determined.”
Research firm IHS Markit recently released a report that indicates the sector’s capital spending will increase from $12 billion last year to $14 billion in 2020 and 2021, but taper off as tax credits expire. Wind operators can take advantage of federal tax credits if they begin construction before year-end.
Texas remains the wind energy leader, with 27,036 MW, followed by the “wind alley” states of Iowa (8,965 MW), Oklahoma (8,072 MW) and Kansas (6,128 MW). California rounds out the top five with 5,842 MW.
VALLEY FORGE, Pa. — PJM staff and stakeholders kicked off Thursday’s Markets and Reliability Committee meeting with an homage to Denise Foster, the RTO’s vice president of state and member services, on her last day with the organization.
“Denise has always been committed to the success of PJM,” said Stu Bresler, senior vice president of market services. “She was very adept and very skilled at building, maintaining and, if I may, fostering relationships.”
Foster resigned in September, much to the disappointment of stakeholders — particularly state consumer advocates — who described her as engaging, personable and sharp. Bresler echoed those warm sentiments in his send-off, saying that Foster served as a mentor to other staff and provided great “insights on the substance of what we do at PJM.”
“She made tough decisions when she needed to and followed through on those decisions when she needed to and really earned the respect of staff here at PJM,” he said.
The MRC endorsed new load management and price-responsive demand testing rules for Capacity Performance resources after PJM said old measures failed to mimic real-life emergency procedures. (See PJM Stakeholders Support More Realistic DR Testing and “Stakeholders Urge Consensus on Load Management Testing Requirements,” PJM MRC/MC Briefs: Sept. 30, 2019.)
The new rules, effective with the 2023/24 delivery year, would give PJM authority over scheduling tests — instead of the resource itself — and provide advanced notification so participants can prepare. The changes would implement a three-step system that gives resources first notice of an upcoming test one week prior to the two-week testing window, with additional alerts by 10 a.m. the day before and the day of the scheduled test. There will be one test per year when there is no event, with half of resources tested in winter and the other half in summer.
The current rules, developed when demand response availability was limited to just six hours a day over the summer, require one test during the summer. They give resources a two-day warning — down to the exact hour — and provide unlimited retesting.
Enel X North America, sponsor of an alternative package that provided a week-ahead notification of a one-week testing window, withdrew its proposal Thursday and encouraged members to support PJM’s plan instead.
“Both sides gave some blood here,” Enel’s Brian Kauffman said. “There’s some philosophical questions that won’t be answered here and will ultimately end up before FERC.”
Stakeholders Mull Tx Asset Management Discussion
Stakeholders will once again consider assembling to discuss how incumbent transmission owners make asset management decisions and whether those projects should stay outside of the regional planning process.
Ed Tatum, vice president of transmission for American Municipal Power, proposed a problem statement and issue charge that would create a special session of the MRC to discuss what criteria TOs should observe before determining their infrastructure has reached the end of its life and whether those determinants could be — or even should be —standardized across all zones.
“It’s important for the stakeholders to weigh in as to how they think this process should work,” Tatum said. “There’s going to be some disagreement, and we need to get some clarity from Washington, D.C., as we go to Federal Energy Regulatory Commission.”
Currently, PJM considers projects related to local asset management as supplemental to the Regional Transmission Expansion Plan and only studies their impacts on the grid’s reliability — not whether the proposals are necessary or the most cost-effective solution. AMP and others have argued that local replacement decisions have regional implications and, therefore, PJM should take over planning in order to assure new projects will not just solve reliability concerns, but also support the “grid of the future.”
“We have talked around this issue so much in recent years, perhaps there’s a degree in fatigue in thinking about it,” said Susan Bruce of the PJM Industrial Customer Coalition. “The first time we went through this, we didn’t have as much clarity as to how PJM was viewing these issues. I think we have a better appreciation for PJM’s asset management concerns in this space.”
Both staff and PJM’s Board of Managers maintain that FERC precedent leaves asset management up to the discretion of TOs, where the local planning expertise lies. Incumbent TOs agree.
“By having PJM responsible for end of life, you are putting more liability on PJM and its membership,” said Pulin Shah, director of transmission strategy and contracts for Exelon. “Even if an artificial end-of-life criteria is established, the transmission owners will still need to move forward with their own end-of-life decisions. Having PJM develop or create some may result in significant increase in supplemental spend if PJM now has to take on this responsibility.”
Tonja Wicks, manager of federal regulatory and regional affairs for Duquesne Light Co., said the term “end of useful life” is what both the industry and FERC have defined and accepted. She then reiterated that the commission concluded that planning for these particular assets is “beyond the scope of PJM’s authority” and questioned whether the newly created term “end of life” was an oversight or if AMP concedes that the FERC term and definition “are what we are working from.”
“There is no industry accepted definition of ‘end of life,’ so we are trying to understand how to work out this issue based on a term that has not been defined,” she said. “We are trying to get an understanding of what we are talking about because there is no such term.”
Tatum said he hopes “TOs will indeed come to the table and come up with some creative solutions that hopefully we can find a consensus around.” While PJM didn’t move off of its long-held position on its authority over supplementals, staff said the conversation was still worth having.
“We will not be put into a position to do condition decisions or asset management-type decisions,” said Ken Seiler, PJM’s vice president of planning. “It’s not our authority to do that, but there is solution space here.”
The MRC will vote on the initiative at its Dec. 5 meeting. Notably, the Planning Committee turned down the problem statement at its September meeting. (See “PC Says ‘No’ to End-of-life Transparency Discussion,” PJM PC/TEAC Briefs: Sept. 12, 2019.)
FTR Market Rule Changes
PJM presented the first round of recommended rule changes for its financial transmission rights market in the wake of the GreenHat Energy default.
Brian Chmielewski, manager of market simulation, said the recommendations will improve PJM’s credit risk policies after the Financial Risk Mitigation Senior Task Force delegated a more holistic FTR market review and possible design changes to a separate MIC task force.
First, PJM suggests hosting five long-term FTR auctions a year, instead of just three, in order to increase oversight and visibility into portfolio conditions so that more collateral can be collected if necessary.
“One of the things we saw with GreenHat, between December and June there was a massive devaluation in that portfolio, so this would have an auction right in March to catch that sooner,” Chmielewski said.
A second recommendation would alter the structure of Balancing of Planning Period FTR auctions so that participants can buy and sell in any month of the year, rather than being limited to a specific quarter.
The FRMSTF voted 75% in favor of the changes. MRC endorsement is scheduled for Dec. 5, with implementation effective in 2020/21.
2019 Reserve Requirement Study results, including updated values for the installed reserve margin and forecast pool requirement, which reset key parameters for the RTO’s upcoming capacity auctions. (See “2019 Installed Reserve Margin Study Results,” PJM PC/TEAC Briefs: Oct. 17, 2019.) Also approved by the Members Committee.
WASHINGTON — The International Summit on the Electric Transmission Grid was billed by trade group WIRES as an opportunity “to discuss and support the robust interregional and cross-border grid of the future.”
But though it was hosted at the Canadian Embassy and featured several Canadian speakers, the discussion mostly centered on the first part: interregional transmission lines — and, more specifically, those that cross state borders rather than international ones.
After all, as more than a few speakers noted, building interstate transmission lines in the U.S. is hard enough without the additional burden of getting a presidential permit to cross national boundaries.
The drive to build both interstate and international long-distance, high-voltage transmission is the same: moving vast amounts of renewable resources to serve growing state demand, itself driven by state and company emissions goals.
In the U.S., California and the Desert Southwest have abundant solar, and the Midwest and Texas are replete with wind, while Canada has more hydropower than it needs to serve its load, located mostly along the U.S. border.
It’s so abundant that the word “hydro” is often used as shorthand for “electricity,” even if it’s “not necessarily generated by hydro assets,” said former U.S. Ambassador to Canada Gordon Giffin, now a partner with Dentons. “In Ontario, there’s probably 50% nuclear power generation, and it’s all called ‘hydro.’”
But Canada does not face all the same challenges as the U.S. when it comes to building long-distance, high-voltage transmission lines.
One reason comes down to simple geography. Canadian provinces are much larger than America’s states: Though the two countries are about the same size, Canada only has 13 provinces. Lines need to run vast distances from the water in the north to the load centers in the south, but most of the northern land is “open and expansive and owned by the Crown,” said Mike Martelli, president of renewable generation for Ontario Power Generation (OPG), referring to the government.
There’s also no federal entity similar to the Department of Energy or FERC that oversees interprovincial transmission. Provinces need only work with each other to site lines, and many provinces own their own utilities, “Crown corporations” such as OPG, BC Hydro, SaskPower, Manitoba Hydro and Hydro-Québec.
“All the provinces have 100% jurisdiction … so it’s a much easier discussion, and it’s a discussion where we can talk more about … the economic benefits, the jobs, the benefits to First Nations and our communities, and all that information is used in making that informed decision at a provincial level,” Martelli said.
Still, interprovincial transmission is uncommon, Martelli said. “All the provinces put up barriers. They like to develop a homegrown solution. And that’s where I think we have to change our thinking, and the true solution is going to be a more integrated approach.”
The final major difference between the U.S. and Canada: politics.
The summit was held Oct. 24, just a few days after Canada’s federal elections. “When the people were interviewed on the street about what’s their No. 1 issue, it’s climate change,” Martelli said. “It wasn’t their taxes. We’re tremendously taxed. … We have high, very high taxes. It wasn’t taxes; it wasn’t health care; it was climate change.”
In May 2009, Ontario passed the Green Energy Act, which created feed-in tariffs for renewable resources. As a result, Martelli said, the province retired all 7 GW of its coal plants and now has 6 GW of wind and 3 GW of solar. “Prices went up about 40%, and people were terribly upset,” he said. “But Ontarians seem to be warming up to the idea” because of their prioritization of emission reductions.
Canada’s generation is “just over 80% emissions-free, and we’re working to make it even cleaner by phasing out coal-fired generation across the country by 2030 and developing small-modular nuclear reactors to transition remote and northern communities off diesel,” Martin Loken, minister of political affairs at the embassy, said in opening the conference.
South of the Border
“For the United States, the integration with Canada, and the opportunities for getting additional carbon-free electricity is absolutely essential” to reaching the targets under the 2015 Paris Agreement on climate change, said Ernest Moniz, former secretary of energy under President Barack Obama. “We have to get the infrastructure to support it.”
He talked about “an absolutely beautiful case” under Section 1222 of the Energy Policy Act of 2005, Clean Line Energy Partners’ Plains & Eastern Clean Line. “It was a beautiful example to implement, and the only problem was called ‘Arkansas.’”
Michael Skelly, co-founder and former president of Clean Line, was there to talk about the lessons learned of his company’s failure. Some of them he only learned “after reading the book” on the subject, he said, referring to The Wall Street Journal reporter Russell Gold’s “Superpower.” (See Book on Tx Developer Transmits Climate Hope.)
One lesson he focused on was the mistake of putting transmission before generation. “We may have been too early. If you look at how transmission is built around the world, [people] often enough build the generation first,” said Skelly, now a senior adviser with Lazard. “The good news in the United States is we’re doing exactly that. … We have a huge renewable expansion taking place, particularly in the center of the country. …
“We sort of thought that would happen” when Clean Line was proposing its projects, “but sometimes people need to see it actually happening before they realize, ‘Wow we have to do something about this problem,’ as opposed to a projected problem.”
Skelly clarified that he was not saying this “bass-ackwards” way of designing the grid was good. “It’s only a good thing to the extent that we go, ‘Oh wow, we have to go build this transmission because we just spent all this money on generation.’”
Discussion on Skelly’s panel — which included Martelli, the American Wind Energy Association’s Amy Farrell and the Solar Energy Industries Association’s Katherine Gensler — turned to criticism of RTOs and their transmission planning processes. Farrell and Gensler agreed that the RTOs underestimate the amount of renewables expected to come online when they plan their grids.
“Planning transmission to meet policy goals; planning for interregional transmission: These are the right goals, and nobody has cracked that nut yet on how to do it,” said Gensler, SEIA’s vice president of regulatory affairs. “Outside of California, no future scenario, not a single one, has 20% solar in it. Some of them don’t even have 20% renewables in them. … We have to plan for a rapidly decarbonizing future, and that is hard for people.
“A lot of the planners want to be very conservative,” Gensler continued. She pointed to wind consistently outperforming what RTOs expected within their 10-year scenarios.
Farrell, AWEA’s senior vice president for government and public affairs, noted that FERC is reviewing its transmission incentives policy, but “there hasn’t been a desire to really [review] Order 1000,” the goal of which was partly to encourage transmission planning between RTOs. “You have to look beyond just incentives and existing transmission improvements, and start looking toward fixing this planning process, because … it’s not about enabling renewable deployment as it is … leaving money on the table. Part of FERC’s mandate is to help drive toward a lowest-cost solution, and we don’t have a process for that right now.”
“The turf wars and feuds between RTOs are legendary; MISO and SPP, these people, for reasons that are often lost to the mists of time, they don’t really like each other that much, and they don’t work well together,” Skelly said. “So the notion that FERC’s going to pass something that says, ‘Hey, you guys, coordinate and work together’ … come on. It has not happened, and it’s not going to happen.”
In a later panel, MISO President and COO Clair Moeller disputed that, saying, “I’d submit we don’t actually have a planning problem. We have an objective problem. The reason we don’t get the answers that everybody agrees with is that people’s objectives are different.
“Lanny and I had a fistfight in the bathroom because RTOs don’t get along well,” he joked, referring to Lanny Nickell, SPP senior vice president of engineering, who was in the audience. “Well, that’s simply not true. The simple fact is the objectives are different. … Until we can get the objectives so they line up [around a policy consensus], the planners are going to be frustrated because we can’t tell them what we like.” He noted that the last of MISO’s multi-value projects, approved by the RTO in 2011, “won’t go into service until probably 2022. That’s not a planners’ problem. That’s a regulatory problem.”
Skelly also described the confusion that state regulators have to endure when being pitched multiple interstate lines. “We need policy mechanisms so that the RTO shows up and FERC shows up. Somebody needs to show up from some sanctioned body to say, ‘Yes, this makes sense.’”
But FERC commissioners “hate telling state regulators what to do,” Gensler said. “That is a fate worse than death for most FERC commissioners.”
As a potential solution, Skelly pointed to Sen. Martin Heinrich’s (D-N.M.) announcement that he would introduce bills to create an investment tax credit for “regionally significant” transmission projects and to direct FERC “to improve its interregional transmission planning process.” Heinrich, however, has been introducing similar legislation since 2015 to no success.
“I thought, up until a few minutes ago, that our process was very political,” Martelli said. “But listening to this, I’ll take our process any day.”
“You guys were smart enough to organize your provinces in a north-south fashion,” Skelly quipped.
BALTIMORE — Competitive transmission developers made a familiar argument at the Organization of PJM States Inc.’s annual meeting last week: Supplemental projects undermine regional planning efforts and PJM should do something about it.
But PJM staff aren’t willing to accept the risks that come with managing supplementals and insist that FERC precedent prohibits the RTO from intervening anyway. Incumbent transmission owners agree, insisting that decisions about when to replace aging infrastructure come with many specific caveats that a regional planning organization doesn’t necessarily understand.
It’s a viewpoint FERC endorsed in two CAISO orders in September 2018 (EL17-45 and ER18-370), Ken Seiler, PJM’s vice president of planning, said while participating on an OPSI panel with the D.C. Office of the People’s Counsel, LS Power, American Municipal Power and FirstEnergy.
In the former proceeding, the commission rejected a complaint from local and state regulators that said Pacific Gas and Electric violated Order 890 because the majority of its transmission planning occurs behind closed doors. FERC said asset management projects that only produce “incidental” increases in transmission capacity aren’t beholden to the transparency provisions of the order. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)
The commission reiterated this opinion in the latter proceeding that turned down the California Public Utilities Commission’s request for a show-cause order finding that Order 890 governs transmission owners’ planning for self-approved projects.
“A lot of this issue around end-of-life projects has been formed by us based on these orders,” Seiler said. “The orders specifically state that end-of-life criteria is not within the RTO’s purview and it’s not their expertise. The ISO shall do the planning, and the TO shall do replacement.”
LS Power and AMP interpreted FERC’s comments in the California dockets differently, however.
“In FERC’s California order, the commission said supplemental projects in PJM are a matter of PJM choice,” said Sharon Segner, vice president of LS Power. “Not a FERC mandate.”
“I don’t think you guys are reading that right,” Ed Tatum, AMP’s vice president of transmission, told PJM staff. “I think the commission took great pains to differentiate between what’s going on in California and what’s going on in PJM. We’ve really got to get it straight as to what we are talking about here, as far as PJM being able to set its own destiny.”
The commission only briefly addressed the PJM matter in the 2018 CAISO orders, calling its February 2018 ruling on PJM supplementals (EL16-71, ER17-179) “inapposite” to the issue at hand in California.
“The question of whether asset management projects and activities that do not increase the capacity of the grid must go through an Order No. 890-compliant transmission planning process was not at issue in the Feb. 15 PJM order,” FERC wrote in both CAISO orders. “Instead, the Feb. 15 PJM order examined the PJM transmission owners’ implementation of the process for planning supplemental projects, a process that is set forth in the PJM Operating Agreement and Tariff.”
No Authority, Expertise
PJM estimates members spent $6 billion on supplemental projects in 2018 — triple the amount invested in baseline upgrades that same year. Tatum said members have spent $29.9 billion on supplemental projects over the last 14 years, more than half of which TOs proposed after 2013. Baseline spending, meanwhile, will reach $30.1 billion by the end of the year, he said.
“Locally cost-allocated projects don’t go out for competition,” Segner said. “If you can do everything through local planning, then all of a sudden there’s not regional needs. There’s no coincidence that this world started aggressively in 2013 when FERC Order 1000 went into effect.”
“It’s very clear in our mind that TOs have the obligation to maintain their system, but as we go through and decide what is asset management … if you’re replacing it, that’s something called planning, and we think there is a bright line there,” Tatum said.
PJM-TO baseline and supplemental projects by proposal year, 2005-2019 | AMP
Under current rules, incumbent TOs submit supplemental projects for inclusion in PJM’s Regional Transmission Expansion Plan. The RTO studies the proposals for impacts on the grid’s reliability but doesn’t make determinations about whether the projects are necessary or the most cost-effective solution. Further, these projects often encompass asset replacement and upgrades that incumbent TOs say they are best prepared to handle. Seiler agreed, noting that PJM isn’t in the business of “condition assessment” and isn’t involved in the day-to-day management of TOs’ infrastructure.
“When we talk supplemental projects, we are talking aged infrastructure … that’s predominantly the type of projects we are focused on,” said Robert Mattiuz, vice president of transmission for FirstEnergy. “We do not want to be in a position where we run our transmission system to failure, so we are proactively addressing this issue.”
There’s no uniform set of standards for determining when an asset has reached the end of its life, Seiler later told RTO Insider, meaning that PJM must rely on local TOs to provide that knowledge. While he couldn’t verify AMP’s data about the growth in supplemental spending, he said PJM’s last wave of transmission buildout occurred more than three decades ago and suggested that the increase in spending over the last few years could be expected based on the age of the current system alone — though age isn’t the only factor TOs consider when replacing infrastructure, he clarified.
He also noted that PJM’s spending looks much less dramatic in comparison with other RTOs and ISOs when investments are load-weighted.
“I’d say PJM spending looks to be about average or even below-average in those terms,” he said.
Seiler’s comments reflect sentiments shared by Dean Oskvig, chair of the PJM Board of Managers’ Reliability Committee, on Oct. 4 that the managers’ review of supplemental projects concluded that the RTO’s role “can be expanded in some areas but also remains appropriately constrained in others.”
“PJM does not have the authority or expertise to assume responsibility for asset management decisions or to determine when a facility is at the end of its useful life or otherwise needs to be replaced,” he said. “Those decisions are the sole responsibility of the transmission owner. PJM has the authority, expertise and the obligation to develop the RTEP. In some circumstances, PJM may be in the best position to determine the more cost-effective regional solution to replace a retired facility. PJM welcomes input from stakeholders to determine under what circumstances PJM might assert that authority.”
Erik Heinle, of the D.C. OPC, said PJM’s ability to foster competition and innovation should naturally extend to supplemental project planning.
“We don’t want to just replace 50-year-old substations with the newer version,” he said. “One of the great successes of PJM is competition in the marketplace. … Why can’t we have that in the transmission space too? We need to make sure we are replacing these aging facilities … not with what we need now, but with what we need in the future.”
LITTLE ROCK, Ark. — After a one-year drop, SPP’s administrative fee will resume its upward climb in 2020 with the Board of Directors’ approval last week.
The directors signed off on a 9.1% increase in the fee to a record high of 43 cents/MWh. The fee dropped to 39.4 cents last year following an $8 million overcollection in 2018. It is projected to reach 46.6 cents in 2022.
The Finance Committee based its recommendation to the board on a net revenue requirement (NRR) of $172.3 million next year, compared with $157.5 million the year before. The NRR is composed of operating expenses (excluding depreciation and FERC assessment), principal payments on loans for capital expenditures and a capital reserve fund.
The board also approved the committee’s recommended budget, which includes a 6.5% increase in operating expenses to $209.1 million and a slight uptick in capital expenditures of $15.7 million.
Oklahoma Gas & Electric, Public Service Company of Oklahoma and Southwestern Public Service were among those that raised concerns over the increases. Director Bruce Scherr, who chairs the Finance Committee, told members that they were looking at a “cash-flow” budget, not a “profit” budget.
“Your comments are not new to us,” he said. “We’re going to keep a close eye on cash-flow improvement. What you should be concerned about is if we didn’t care about that, and we let [the increase] go to be institutionalized without further evaluation.”
SPS opposed the motion to increase the budget, while OG&E and Liberty Utilities abstained. All three companies abstained from the Members Committee vote to approve the administrative fee.
SPS’ David Hudson reacted negatively to the increases, pointing out that his company is “fighting hard” to keep its operating and maintenance expenses flat.
“We see this year after year,” he said. “This goes into retail rates. A 10% increase is too high.”
“We’re concerned with the revenue requirement and the increase in costs we continue to see,” OG&E’s Greg McAuley said. “We understand the nature of most of it, but in the world we operate [in] today, we continue to keep our operating costs flat. We look for the organization to meet us, because that’s what the customers demand of us.”
Chart reflects the actual NRR and admin fee charged for 2019-2018 and the budgeted/forecasted NRR and admin fee for 2019-2022. The NRR excludes prior-year true-up amounts. | SPP
Board Chair Larry Altenbaumer took slight umbrage at the comments, reminding members of what they get for the costs.
“The organization has done a phenomenal job of living within its budget,” he said. “I’m not trying to minimize any of the comments, but the thing that continues to gnaw at me a little bit is the other side of the equation … the pushback is always on costs. There’s never any recognition of what members get for that cost.
“I continue to believe this organization is providing significant benefits that outweigh the costs you are paying. That doesn’t reduce our efforts to keep the pencils as sharp as we can, but constantly hearing one side of the argument is unfair to this organization,” he said.
The budget does not include costs for SPP’s reliability coordination functions in the Western Interconnection, which Scherr said have been budgeted separately and will be financed through debt and paid back over time.
SPP expects its employee headcount to increase to more than 650 by 2021 because of RC West needs and additional engineers added to handle the generation interconnection studies’ workload.
2019 ITP Portfolio: 44 Projects, $336M
The directors signed off on the 2019 Integrated Transmission Planning (ITP) 10-year assessment that SPP said will reduce congestion costs by 21% on average and lead to projected future net savings of up to 23 cents on average monthly residential bills in the footprint.
The portfolio’s 44 projects have an estimated engineering and construction cost of $336 million and include 166 miles of 345-kV transmission. Lanny Nickell, SPP’s senior vice president of engineering, said the assessment projected considerable wind and solar growth, conventional generation retirements and the effect of new technologies.
Members resumed a discussion begun at the Markets and Operations Policy Committee in mid-October over the futures used in the 2021 10-year assessment. A carbon-reduction future envisioning as much as 55 GW of wind and solar energy in 2031 was eliminated. (See SPP Debate: How Green is Our Future?)
NextEra Energy Resources’ Holly Carias pointed out that stakeholders “already know we’re going to exceed” the assessment’s base case future, which projects 2 GW of additional wind energy by 2029 beyond the 22 GW already on hand. Nickell said that it’s “more likely” that 8 GW of wind capacity will be added over the next 10 years.
“Having realistic futures is extremely important. What we’re seeing out of the 2021 futures is a lot more realistic than we’ve seen previously, so I think we’re on the right track,” Carias said. “We need to look differently at how we’re looking at benefits. Currently, we’re looking at benefits to load. Maybe it’s time to look at benefits to generation. Maybe [generation] should pay for more of the costs.”
“We did assess benefits to generators not committed to load. It’s a fairly large number,” Nickell said. “What we haven’t done yet is figure out a way, or opportunity, for other parties with generators not committed to load to participate in the funding. We don’t have the Tariff mechanism.”
“We have questions, or concerns, with the way the new ITP process favors [the emerging technologies] future with more wind, which drives more transmission … and drives further costs,” McAuley said. “We’re waiting to see a confirmation that the benefits that come out of these studies will continue to increase at the same rates we’re being told they will. We’re really unsure at this point, after a year of this, about the benefits and cost allocation.”
Sunflower Electric Power opposed the recommendation during the Members Committee vote. OG&E, Oklahoma Municipal Power Authority, Golden Spread Electric Cooperative and Tri-County Electric Cooperative abstained.
Board Sends Fast-start Tariff Change to FERC
The board approved a Tariff revision that complies with FERC’s directive to allow fast-start resources to set clearing prices, while also supporting the Market Monitoring Unit’s opposing filing with the commission.
MMU Executive Director Keith Collins told board members that the Monitor has identified two major market-design flaws in the revision request (MWG RR375): It applies the mitigation process in the price calculation and not the dispatch instruction’s calculation, allowing market participants to potentially manipulate the market; and it allows market participants to change start-up offers and no-load offers after the fast-start resources’ commitment has occurred.
Collins said that because the offers can set price for other resources, the MMU believes “this sends an inappropriate price signal and allows market participants to manipulate the market.” The Monitor has proposed applying the mitigation process in calculating both the dispatch instruction and price, and that the start-up and no-load offers evaluated at the time of commitment be used in the fast-start resource’s modified energy offer. (See “Members Endorse Quick-Start Revision,” SPP MOPC Briefs: Oct. 15-16, 2019.)
SPP staff said RR375’s scope was limited to meet only FERC’s requirement. The Members Committee voted unanimously in favor of the motion.
Golden Spread opposed the revision at the MOPC and said it would likely file comments at FERC.
“This is an incremental step,” the co-op’s Mike Wise said, noting it has engaged the Brattle Group for support. “We don’t believe SPP has complied with FERC’s desire on this.”
“I’m concerned some of what has to be done has to be resolved by FERC,” Altenbaumer said. “We can appropriately get the issue to FERC and have them resolve it in a constructive manner.”
The commission in June found the grid operator’s quick-start pricing practices to be unjust and unreasonable because they don’t allow prices to reflect the marginal cost of serving load and directed the RTO to make six Tariff changes in response. (See FERC Orders Fast-start Rules for SPP.)
Expressing a need for “fresh thinking and planned transition,” SPP CEO Nick Brown announced to stakeholders that the board meeting was the last for Directors Emeritus Jim Eckelberger and Harry Skilton, and Director Phyllis Bernard.
The three have served together since 2003 and have a combined 55 years of experience as directors. Eckelberger served as the board’s chairman for 14 years before stepping aside last year. (See Eckelberger, Skilton Step Down from SPP Board.)
Eckelberger, Skilton and Bernard were all honored with resolutions from SPP and standing ovations from its members. Bernard participated by phone.
The board’s membership currently stands at nine active members following the approval of Julian Brix and Mark Crisson to three-year terms that begin in January. Brix has been a director since 2008 and Crisson since 2017.
The Corporate Governance Committee later this year will interview candidates for Bernard’s vacancy.
SPP to Pay up to $8.6M in Pension Benefits
Directors approved the Human Resources Committee’s recommendation to offer lump-sum payments to terminated SPP employees vested in the RTO’s pension plan but not yet drawing a benefit. The proposal would amount to an $8.6 million payout if all 164 eligible former staffers draw from it.
Based on annual premium savings of $100,000, current interest rates and actuarial tables, SPP would break even with just one participant in the buyout, staff said. They said advisers have told the RTO to expect a “take rate” of about 100 eligible participants.
Members and the board also approved the Value and Affordability Task Force’s recommendation to accept its report and recommendations and dissolve the group. (See SPP Value Group Finds No ‘Silver Bullets.)
Consent Agenda Clears Project Resets
The consent agenda was passed without dissent, resulting in the approval of APEX Clean Energy’s upgrade to the Neosho-Caney River 345-kV line in Kansas, scheduled to go in service next year, and a pair of baseline resets:
Evergy’s $54.1 million update for a 345/138-kV transformer and 138-kV transmission line project, estimated at $67.1 million in 2017.
Evergy’s $34.4 million update for network upgrades on a 138-kV circuit, which was originally projected to cost $58.3 million.
Two revision requests were on the consent agenda:
TWG RR363: Defines existing transmission facilities’ “material modification” as being “based on engineering judgment” in NERC’s facility interconnection studies (FAC-002) compliance.
TWG RR364: Reduces the planning criteria’s language on equipment rating, which is already covered by NERC Reliability Standard FAC-008.
LITTLE ROCK, Ark. — SPP’s Regional State Committee last week unanimously endorsed the elimination of revenue credits for sponsored transmission upgrades and the 2019 10-year transmission planning assessment.
Regulators asked to hear from renewable energy stakeholders, who participated in the Markets and Operations Policy Committee discussion of the Tariff revision earlier in October. The MOPC unanimously approved the change, which replaces Attachment Z2 credits for sponsored upgrades with incremental long-term congestion rights (ILTCRs), effective February 2020. (See “Stakeholders Endorse Eliminating Z2 Revenue Credits,” SPP MOPC Briefs: Oct. 15-16, 2019.)
EDP Renewables’ David Mindham repeated the industry’s position that the revision doesn’t comply with FERC’s policies on interconnections (Order 2003) and long-term firm transmission rights (Order 681).
“We don’t oppose removing Z2 credits,” he said. “We don’t feel there’s enough value in ILTCRs to be complying with FERC Order 2003.”
“I do agree there are some things that need to be fixed,” South Dakota Public Utilities Commissioner Kristie Fiegen said. “But I believe MOPC’s action is appropriate. I believe Z2 credits need to eliminated sooner rather than later.”
SPP General Counsel Paul Suskie argued that Z2 credits are not required by FERC policy and are instead a “self-imposed requirement” implemented through the stakeholder process.
“If an entity thought our ILTCRs do not comply with FERC, we would not appeal to FERC,” he said.
The RSC also signed off on SPP’s Integrated Transmission Planning 10-year assessment, a portfolio of 44 transmission projects with a total engineering and construction cost of $336 million. The 2019 ITP, the first after stakeholders revised the planning process, includes 166 miles of new extra-high-voltage transmission and 28 miles of rebuilt high-voltage infrastructure.
“We hope to solve both reliability and economic needs in a way that optimizes performance,” Senior Vice President of Engineering Lanny Nickell said. He said the portfolio is expected to lower congestion costs by more than 63 cents/MWh, a 21% reduction.
Nickell said he expects two of 345-kV projects, a 60-mile line in Oklahoma and a 105-mile line in Kansas, to become competitively bid. The projects have engineering and construction costs of $85.9 million and $162.6 million, respectively.
Louisiana’s Campbell: SPP Spending ‘Extravagant’
In a rare appearance before the RSC, Louisiana Public Service Commissioner Foster Campbell laid into SPP for what he termed “extravagant” spending on corporate facilities and executive salaries.
Campbell, a self-described politician whose colorful career includes 26 years in the Louisiana State Senate and multiple failed bids for Congress and the governor’s office, was elected to the PSC in 2002. He normally gives his RSC proxy to PSC legal staffer Dana Shelton. That Campbell is up for election in 2020 led many onlookers to call his comments “political.”
“I’m not trying to be blunt, but telling it like it is,” he said. “The first time I came here, I never saw a building like that. I’ve been to a lot of places: capitols, the White House, fancy hotels … this building costs $67 million. That goes to my customers. I represent my customers, all in North Louisiana, and we have a lot of poor people.”
SPP CEO Nick Brown listened stoically as Campbell criticized him for a salary he said was $950,000. According to the RTO’s 2016 IRS Form 990, the last available through nonprofit tracker GuideStar, Brown’s total compensation was $1.2 million. By comparison, MISO’s 2017 990 lists CEO John Bear’s total compensation at $2.8 million.
“I know the good you’re doing. I hope you realize there are lots of poor folks out there, and I represent a lot of them,” Campbell said. “I would not want my people I represent to know we spend money like this. It’s too much.”
SPP Chairman Larry Altenbaumer cut Campbell off, saying Brown’s salary was commensurate with others in the industry and extolling the work of the Value and Affordability Task Force he chaired. (See SPP Value Group Finds No ‘Silver Bullets’.)
“I spent an entire year, with stakeholder involvement, looking at value and affordability of the organization with respect to our costs and the value delivered,” Altenbaumer said. “I feel very good about the comments we received.”
“I’m sure our architects would be amused that you think that this building is lavishly furnished,” Brown said, describing the building’s use of reclaimed materials and poured concrete for the floors. “Our Finance Committee, that consists predominantly of member companies, oversaw every specific of this building. This building is significantly cheaper than the leased space we were in over multiple locations in the area. To say we’re lavish with our money is simply not true.”
SPP clarified that Campbell’s $67 million figure applies to the value of its infrastructure assets, which includes the $52 million in construction costs for the Corporate Center’s four-story office building, modern operations data center and parking deck, and the backup ops center in nearby Maumelle. The operations center costs include required measures such as storm hardening, backup generation and fuel sources to ensure continued operations, the RTO said.
The RSC took a break after the exchange between Campbell, Brown and Altenbaumer. When the meeting resumed, Shelton was sitting in Campbell’s seat.
The Louisiana PSC is expected to vote on new RTO assignments in January.
Nebraska’s Grennan Elected as RSC President
Regulators approved the slate of officers for the committee’s leadership in 2020, with the Nebraska Power Review Board’s Dennis Grennan succeeding Arkansas Public Service Commissioner Kim O’Guinn as president.
South Dakota’s Fiegen will replace Grennan as vice president, while North Dakota Public Service Commissioner Randy Christmann will replace Fiegen as the RSC’s secretary.
“We have a lot on our plate for the next few months,” Grennan said. “We’ll be working on all of those items.”
O’Guinn in October was appointed to the National Association of Regulatory Utility Commissioners’ board of directors.
Arkansas’ Thomas to Lead OMS Half of Seams Group
Arkansas PSC Chairman Ted Thomas will replace Missouri Public Service Commissioner Daniel Hall as the Organization of MISO States lead on the RSC-OMS committee working to resolve seams issues between the two grid operators. (See OMS Panel Debates Merits of MISO-SPP Seams Projects.)
Missouri PSC economist Adam McKinnie told the RSC that Hall is leaving the commission when his term expires this month.
The committee will meet in an open session on Nov. 17 during NARUC’s annual meeting and education conference in San Antonio. Registration will be available through the OMS website.
