Peak Reliability and PJM Connext have entered the “commitment phase” for their proposed Western energy market, refining their pitch to convince potential participants to finally embrace an organized market for the region.
The organizations on Friday issued a three-page abstract of their new business plan to potential members and has also set up a public comments page on a partnership for what could possibly lead to a Western RTO, an effort that has previously been stymied by difficulties in developing a governance process acceptable to all the states involved.
“It is envisaged that these services will expand over time, evolving towards a full RTO offering. Whether and when this occurs will be a matter for the market’s participants to determine,” the abstract says. The full business plan remains confidential and will require interested parties to enter nondisclosure agreements.
In response to the proposed market plan, CAISO has filed to depart Peak as its reliability coordinator (RC) and developed a rival plan to offer RC services across the West to Peak’s existing customers. (See CAISO to Depart Peak Reliability, Become RC.) The ISO is also exploring enhancing its day-ahead market and extending it across the Western Energy Imbalance Market (EIM). (See Multiple Entities, Markets Now Beckon in West.)
Peak said it continues to receive notices from utilities intending to withdraw from its reliability services but is not making public the number that have filed. The organization has noted that market participants are highly likely to receive RC services and market services from the same source.
An outline of the Peak Reliability/PJM Connext reliability and market services offering | Peak Reliability, PJM Connext
“I can say we have not received notices from all of our funding parties,” Peak spokeswoman Rachel Sherrard told RTO Insider. “I would note that, with the exception of one entity, all notices received so far are revocable.” The non-revocable notice is from CAISO, which will leave Peak on Sept. 2, according to organization documents.
The Peak/PJM commitment phase will consist of confidential meetings with interested parties “to review more details on the plan’s assumptions, market size scenarios, expected transactional cost ranges, projected aggregate efficiency savings and proposed services within the business plan,” the organizations said.
They envision the market will initially roll out with a day-ahead and real-time market using LMP and forward transmission rights for hedging. A full RTO would then be developed at the behest of market participants. (See Peak Touts ‘Independent’ Western Market Plan.) Existing RC services would be offered as well as balancing authority services, transmission operation, real-time grid monitoring and control, and interregional congestion management. A NERC-certified RC is needed to comply with the reliability organization’s standards.
Peak has highlighted its knowledge of the Western grid as an RC, while PJM brings its experience in market design and operation. (See PJM Chief Confident on Western Market Proposal.) The real-time market would include spot energy, synchronous and nonsynchronous reserves, and frequency regulation. The day-ahead offering would include a virtual energy market, while the FTR offering would allow a forward hedge price differential between nodal and aggregate locational pairs.
Peak says its funding level will remain flat through 2019. It has scheduled an April 11 conference call on its market initiative.
CAISO says it will “shadow” Peak RC services and then launch its own RC offering by spring of 2019.
Unilever, which sells Breyers ice cream, Dove soap and hundreds of other consumer products, plans to eliminate coal from its energy mix by 2020. It hopes to become “carbon positive” by 2030, by supporting the generation of more renewable energy than it consumes.
Thus far, the company has used onsite solar and power purchase agreements for Texas wind power. But the company has been frustrated in its inability to do more. “If we’re buying wind in Texas and trying to get it to my plant in Virginia, in Tennessee, in Missouri … right now we’re just not able to do that,” Stefani Millie Grant, the company’s senior manager for external affairs and sustainability, said last week.
“If we’re going to actually get [renewables] … actually running our facilities, instead of just being out there buying the [renewable energy credits], we’ve got to really focus on transmission.”
| David Gardiner and Associates for the Wind Energy Foundation
Even as President Trump has moved to undo the Obama administration’s climate initiatives, large corporate energy buyers such as Unilever have accelerated their commitments to purchase carbon-free electricity. But their efforts may be frustrated because of insufficient transmission to move Midwest wind power to load centers, according to a study released by the Wind Energy Foundation. The study was the subject of a webinar last week by Americans for a Clean Energy Grid (ACEG), a coalition whose members include the Natural Resources Defense Council, WIRES, ITC Holdings and American Electric Power.
15 States Hold Most Onshore Wind
The study concluded that transmission expansions currently planned will likely be insufficient to support large corporate energy buyers’ renewable energy goals because most of the solar and wind power potential is in 15 Midwestern states, far from load centers. The 15 states hold 88% of the country’s wind technical potential and 56% of its utility-scale solar photovoltaic potential, but they are home to only 30% of projected 2050 electricity demand.
15 Midwestern states have 88% of the U.S.’s total onshore wind potential and 56% of its utility-scale solar PV potential. But they are far from load centers and will consume only 30% of projected electricity sales in 2050. | David Gardiner and Associates for the Wind Energy Foundation
This is based on the Renewable Energy Buyers Alliance (REBA) goal of obtaining 60 GW of new renewables by 2025 and the 52 GW of new transmission capacity planned in 14 near-term projects in advanced development in MISO, SPP, PJM and NYISO (see table).
In three of the four scenarios studied, transmission would be insufficient to meet corporate renewable demand. With 9 GW of renewables procured by corporate purchasers since 2013, about 51 GW remain to meet the goal. If RTOs build 90% of the capacity in the 14 projects, only 70% of the corporate demand would be filled, the study said. If corporate procurements fall short at only 20 GW, the transmission projects would meet the corporate needs, the study said.
| David Gardiner and Associates for the Wind Energy Foundation
According to the study, one of the biggest obstacles to bringing more renewable energy online is “the absence of transmission planning across RTOs and other regional planning authorities.”
Not Counting All the Benefits
“I think that current [transmission] planning process doesn’t do an adequate job of really counting up all of the benefits, and then it doesn’t think about it … in a … broader geographic scale,” said David Gardiner, president of David Gardiner and Associates, which conducted the study for the foundation.
“We’ve built the interstate highway system in this country not because the highway system went from point A to point B, and the people along point A and point B paid for it, but because we recognized that it provides national benefits, and therefore everybody contributed nationally. We need to be thinking about how we assess the benefits and think about how we want to pay for things more along those lines than we currently are.”
The study recommends that corporate and institutional energy buyers participate in regional and interregional transmission planning and urges FERC and RTOs to improve interregional planning under Order 1000. It said RTOs should incorporate voluntary, large customer demand in transmission planning.
“While we highlight a few examples in the report of companies like Stefani’s that have engaged in some of the planning for transmission lines, it’s been limited, and we’re going to need to step up the kinds of engagement in the transmission planning process as we go forward,” Gardiner said.
Gardiner’s study found that while transmission planners “in rare instances” account for voluntary goals, such as statements by governors, they do not account for growing voluntary demand from large corporate purchasers. “Instead, RTOs typically only focus on mandatory renewable energy requirements prescribed by [renewable portfolio standards].
“If a governor issues a voluntary goal to develop 1 GW of renewable energy in the state, some RTOs would typically include assumptions to meet that 1-GW target in transmission planning models. Although the goal may not be a mandate … other RTOs do only what FERC requires, which is to ‘consider’ public policy and may ultimately opt not to include state RPSs or other policies in their plans.”
RTOs Respond
Officials of MISO, PJM and SPP told RTO Insider last week they are adding transmission for renewables as best they can under FERC transmission planning and cost allocation rules.
“Lack of transmission expansion to facilitate renewable deliveries across regions is not due to inadequate transmission planning between the regions,” said SPP Vice President of Engineering Lanny Nickell in a statement. “Rather, the lack of expansion primarily derives from the difficulty in achieving agreement among multiple groups of customers as to who receives the benefits and, thus, who should pay for transmission upgrades.”
Nickell noted that SPP and other RTOs consider varying amounts of renewable transfers between regions in their interregional transmission planning studies. “RTOs have largely addressed this issue within their regions due to FERC-approved cost allocation mechanisms for service contained in their areas. However, customers in other regions are sometimes challenged to deliver renewable energy from regions like SPP’s because they are unwilling to bear the costs of required infrastructure upgrades or because it is difficult to find other customers willing to share the costs of those upgrades that they don’t believe benefits them,” he said.
“We believe our transmission planning process does adequately address large customers’ increased demand for renewable energy,” said Eli Massey, MISO’s senior adviser for policy studies, in a statement. “MISO’s top-down transmission planning examines regional economics, and its bottom-up planning examines local load growth and reliability issues in order to optimize the transmission system. MISO’s transmission planning process already facilitates the study’s recommendation that large customers engage in the transmission planning process through the industry sector mechanism of the Planning Advisory Committee.”
PJM spokesman Ray Dotter said the RTO accounts for transmission for renewables through its markets and interconnection process.
“We do not plan or build transmission lines on speculation alone,” he said “The developers of new generation of any type are required to pay for the transmission upgrades necessary to deliver the output of their projects. The principle has been that consumers should not pay for transmission required because of generation developers.”
He noted that PJM’s state agreement approach allows states to take responsibility for the costs of transmission expansions addressing their public policy requirements. FERC approved the state agreement approach in a 2015 ruling as part of the RTO’s plan to integrate multi-driver projects into the Regional Transmission Expansion Plan (ER14-2864). (See PJM Wins OK on Multi-Driver Tx Projects.) PJM said the multi-driver concept could lower the cost of states’ public policy transmission projects by incorporating them in upgrades that address market efficiency or reliability.
Nickell said SPP considers voluntary and mandatory renewable goals in its planning assumptions. “If a wholesale customer, under the SPP Tariff, desires to buy from a new or existing renewable resource to supply the needs or goals of its customers and submits a request for transmission service from SPP, we are obligated to plan the system to accommodate the requested service, as long as the customer agrees to fund any requisite upgrades. SPP will consider any and all requests for transmission service made to deliver energy from existing or future renewable resources to prospective buyers and will direct construction of transmission upgrades on the SPP system needed to accommodate those requests in accordance with the respective customers’ service agreements.”
RPSs — which currently represent 10% of MISO’s load — are considered the base level of renewable penetration in its transmission planning modeling futures. “Large customer demand for renewable energy is included in alternative modeling futures on an additive basis that range up to 30% penetration of MISO system load,” Massey said. “We believe that level of penetration fully captures the stated goals of large customers and still leaves room for additional growth.”
Massey, who also spoke at the webinar, said it is the scheduling of transmission to deliver power under a PPA that signals load growth to MISO.
The RTO also learns of PPAs from stakeholders. “But because MISO is not a signatory to the power purchase agreement, we don’t always know about these power purchase agreements, so it’s difficult to plan in that context.”
ACEG Executive Director John Jimison, who moderated the webinar, noted that “it only takes a couple of years” to bring a wind farm or central solar plant into operation, shorter than the timeline for developing new transmission. “How do you anticipate the need for transmission so that you don’t expect people to put up a wind farm and then wait five years before they can actually transmit the power?” he asked.
Massey said MISO accounts for that disparity through its multi-value projects (MVPs). He cited the wind-rich Buffalo Ridge area of southwest Minnesota, northwest Iowa and eastern South Dakota. “We know that there’s a tremendous amount of wind capacity there, and in the current incentives regime with the production tax credit … and because the cost of wind generators is coming down rapidly, we know that there’s going to be wind locating there.”
MISO has about 37 GW of wind and 21 GW of solar in its interconnection queue. “The good news is that it takes a long time for even those plants to get through the generator interconnection process, and this gives us a little bit of lead time in the transmission planning process to identify projects that we’re going to need on a regional basis, that we can predict based on what the wind capacity is and where we know the load is,” Massey said.
Order 1000
Although Order 1000 requires RTOs to jointly plan transmission with their neighbors — and to “consider” whether needs identified in local and regional transmission plans could be addressed more cost-effectively through joint projects with a neighboring region — it does not require them to build anything.
The commission will conduct a technical conference beginning Tuesday on how RTOs coordinate generator interconnection studies on projects near their seams, saying their practices may not be just and reasonable (EL18-26, AD18-8).
FERC called the conference to address issues raised in EDF Renewable Energy’s complaint against PJM, MISO and SPP last year, which contends that inconsistencies and a lack of clarity in the RTOs’ rules for “affected systems” interferes with developers’ ability to judge the commercial viability of proposed projects. An affected system is one that may be impacted by an interconnection in a neighboring “host” system.
MISO and PJM will decide by May 18 whether to undertake a coordinated system plan study this year, the RTOs said last week.
The decision could be announced at the next Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting on May 11. Staff from both RTOs confirmed the timeline at last week’s IPSAC meeting, which included the issues review required as part of the process of determining whether a study is required.
“We don’t anticipate taking that long,” PJM’s Alex Worcester explained, referring to the May 18 deadline. He later added that PJM is “likely supportive” of a study.
The RTOs will provide justification for their decision, MISO’s Adam Solomon said. It will be based on whether there are projects that “make sense,” addressing reliability issues on either side of the border that are close to each other.
PJM and MISO in January jointly reviewed their separate regional issues, newly approved projects near their border, coordinated interconnection requests and historical market-to-market congestion, which RTO representatives said would form the basis of the study, if it’s undertaken. The results were presented at last week’s meeting, along with analysis of stakeholderfeedback.
RTOs’ Review
Worcester reviewed projects approved through PJM’s monthly Transmission Expansion Advisory Committee analysis, including 27 baseline reliability projects near the RTOs’ shared border, six market efficiency projects and another six supplemental projects.
All reliability issues identified for 2022 are being addressed through a single proposal window open last summer. Market efficiency projects are addressed on a 24-month cycle that last identified issues in October 2016, but an addendum window to address thermal constraints on the Tanners Creek-Dearborn 345-kV line was closed in February. Supplemental projects are developed internally by transmission owners and are not driven by RTO criteria. They’re included with baseline and market efficiency projects in PJM’s Regional Transmission Expansion Plan to allow staff to identify possible reliability or operational performance issues, but they are not subject to staff oversight or approval.
Solomon reviewed the 2018 MISO Transmission Expansion Plan, which began in June 2017 and is scheduled to culminate in December 2018 with approval from the Board of Directors for recommended projects. He highlighted 52 approved projects near the RTO border that might spur interregional projects if there are needs nearby in PJM’s territory. They are all TO-submitted ‘bottom-up’ projects.
MISO is also reviewing 15 of its most congested north/central flowgates, which will be included in its Market Congestion Planning Study this year to potentially identify market efficiency projects, he said. Nearby PJM economic issues could drive the need for an interregional project. He also noted 21 congestion flowgates that were eligible for the MCPS but were excluded for individual reasons.
Stakeholder Issues
The RTOs also reviewed issues identified by stakeholders. Ameren submitted four issues, while three issues Northern Indiana Public Service Co. highlighted were included in Solomon’s presentation.
“We will look at those as appropriate and as they show up in the interregional process,” Worcester said.
NIPSCO’s final concern involved PJM’s finding of 10 facilities with infeasible auction revenue right paths. ARRs are rights to the revenue from congestion charges allocated to firm network and point-to-point customers because they fund the embedded costs of the transmission system. MISO and PJM are each addressing one of the infeasible ties with approved internal projects. Three others have projects under consideration, and two others will be included in a future proposal window. The three remaining infeasible paths are pseudo-tie flowgates. (See “ARR Analysis IDs Constraints,” PJM Planning and Transmission Expansion Advisory Committee Briefs: Nov. 9, 2017.)
Worcester said MISO has no process comparable to PJM’s ARRs, so “if it’s outside of PJM, it’s unclear how it would move through the [RTOs’ joint operating agreement] with the competitive transmission process,” he said. PJM will investigate internally ways to address the issues and engage with MISO on any potential solutions, he said.
Wind on the Wires and EDF Renewable Energy asked that the RTOs re-evaluate previously considered targeted market efficiency projects (TMEPs) that did not qualify last year if congestion has continued.
“We certainly agree with that in principle,” Worcester said. He said the RTOs aren’t planning on reconsidering the Thayer-Morrison project, which Wind of the Wires had specifically requested.
JOA Changes
Seven stakeholders provided feedback on three potential JOA changes, which informed the RTOs’ decision-making on the issues. References to joint economic models will be removed.
“NIPSCO prefers a joint model,” the company’s Clark Gloyeske said, noting past differences between the regional models in wind-unit profiles. “More coordination between the regional models to fix some of these modeling issues would be really helpful.”
The RTOs have decided against changing the number of benefit years, fixed charges and discount rates used in analyses, Solomon said. While changes were recommended, they were “wildly varying” on what the correct number of years should be.
“Considering all the feedback, the RTOs think this should be a regional discussion,” he said. “We think the regional processes are working … and that we shouldn’t be deviating from the regional criteria.”
“I understand the simplicity of working just within the regions … but if the number of years the benefits are calculated over are significantly different … I think there’s a risk of coming up against significant stakeholder or state concern about another region not paying its fair share because they haven’t calculated the same level of benefits over the same years,” said Natalie McIntire of Wind on the Wires.
Solomon acknowledged the “valid concern” but said it had to be weighed against “regional differences.”
“Each region has its own definition of how benefits should be calculated, and that’s in line with what we do with our regional projects,” he said. “Deviating from that for an interregional project would be difficult, but certainly, your point is taken.”
The generation-to-load distribution factor test will be removed, Solomon said, and the RTOs will rely on their own regional materiality tests. This removes a “triple-hurdle concern” that would require projects to pass tests for each region as well as an interregional review, Worcester explained. PJM will develop its test through its recently formed Market Efficiency Process Enhancement Task Force, while MISO is still considering where it will address the question.
“The Tariff is silent on how projects qualify materiality-wise,” Solomon said.
Ameren’s Adam Weber asked that the regions’ materiality tests be delineated in the JOA so stakeholders aren’t surprised by a project not clearing both tests. RTO staff hesitated to endorse that proposal but were aligned on addressing Weber’s concern.
An analysis of site location compared to benefits of interregional projects between MISO and PJM shows that there are nine potential cost-allocation categories into which a project could fit. | MISO, PJM
The grid operators will replace the distribution factor (DFAX) cost allocation method with an approach that allocates costs to the RTO with the reliability need, with split projects allocated based on the ratio of avoided costs. Cross-border baseline reliability projects will be replaced with interregional reliability projects because no scenario exists where the baseline projects would be used. An RTO will be obligated to construct projects that benefit the other RTO, but the benefiting RTO will cover the costs.
“There’s not going to be a scenario where there’s a new project developed and we would need to come up with a new cost allocation methodology,” Solomon said.
The RTOs said they “don’t see a need for” EDF’s request to add benefit metrics for projects, but a second request to broaden the JOA’s definition of a flowgate will be forwarded to the Congestion Management Process Working Group, which has representatives from most RTOs.
The RTOs hope to have the JOA changes in place for the next interregional market efficiency project window, which opens around Nov. 1.
“We’re thinking that a filing should be made by July to allow for the FERC process to go through,” Solomon said.
AUSTIN, Texas — The Public Utility Commission’s open meeting last week was the last for Commissioner Brandy Marty Marquez, who announced March 8 that she is resigning from the commission after five years of service.
PUC Chair DeAnn Walker, who has known Marquez for many years, opened the meeting with words of praise for her good friend. Walker cited her loyalty, wit, tenacity and compassion. And her tears.
“She joked about it, maybe having a tear here and there on some cases,” Walker said of Marquez. “Some people saw that as a weakness, but I saw that as one of her strengths. She was compassionate, but she always ruled on laws and facts.”
“They make fun of me for being a crier over here,” Marquez said during an interview earlier, in which she noted the differences between the political arena, where she spent 17 years, and the regulatory world. Marquez frequently referred to “here” and “there,” nodding over her shoulder to the Texas State Capitol visible through her office window.
“Over at the Capitol, I think I got choked up twice,” Marquez said. “I think I’ve grown a heart over here, which is probably difficult for people who are not in this industry to understand. But when you’re dealing with the kinds of things we deal with here, it’s pretty cool to be a part of it.”
The senior member of the commission, Marquez said she was resigning to return to the private sector. (See Marquez to Depart Texas PUC.) Two weeks later, she said she doesn’t “exactly know what’s next yet.”
Marquez said she’s “led a very blessed life” in that she chooses a path and “something will go horribly wrong.”
“Then I kind of throw it up in the air, and then something I never would have dreamed could happen to me will happen to me. This is kind of a reoccurring theme in my life.”
Such was the case in 2013, when Marquez was Gov. Rick Perry’s chief of staff as the state’s legislative session came to an end.
“I’m a believer that when you feel the whisper of, ‘It’s time to think about doing something else,’ you should honor it, because the whispers eventually become a shout and then a yell,” Marquez said. “I knew I needed to leave Gov. Perry’s office. I had worked for him for several years, but I had no idea what I wanted to do.”
Unexpectedly, Perry asked Marquez if she would serve on the PUC. She agreed.
“It was perfect,” she recalled of the switch. “It’s been wonderful.”
Marquez first had to acclimate herself to the regulatory pace. At the Capitol, she said, “You have five minutes to make a decision. Things are happening so quickly over there. This bill is up. Does it do this? What’s the answer?
“In the regulatory world … you take your time to get more information,” Marquez said. “If you’re unsure, it’s OK. There’ll be more time. Over there, you’re constantly thinking about the political angle. They don’t want you to be political here. They want you to just look at the problem and solve it.”
At the Capitol, the political crowd is always looking for a “seam,” Marquez said. If a lawmaker’s bill gets shot down, they look for someone else’s bill that might work. If that bill doesn’t work, they look for another.
“In the regulatory world, there are no seams. There are well-plotted streets and sidewalks, and maybe if you want to get crazy, you can get off the street and get on the sidewalk. You have to have that very prescribed predictability, because you can’t ask people to invest billions and not know the rules of the game.”
A San Antonio native, Marquez earned her undergraduate degree from the University of Texas at Austin and her law degree from St. Mary’s University in her hometown. She calls herself a “child of chaos” who grew up in the Capitol, working first as an intern while also going through law school. Marquez served in numerous leadership positions on Perry’s staff, including as his budget director, his policy director during his successful 2010 gubernatorial campaign and as his chief of staff during Texas’ 83rd legislative session.
Marquez joined the PUC during the summer of 2013, reuniting with fellow Perry administration veterans Donna Nelson and Ken Anderson. It was a turbulent time, Marquez said, with a severe drought driving concerns over ERCOT’s resource adequacy.
Within a year, Energy Future Holdings, a group of private equity firms that acquired Texas energy firm TXU in a 2007 leveraged buyout, declared bankruptcy. The PUC would be consumed with protecting the state’s ratepayers from EFH’s financial travails during attempts by several companies to acquire its Oncor utility. California’s Sempra Energy finally earned the golden ring earlier this year. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
A similar concern for ratepayers drove the PUC to push Oncor and Sharyland Utilities to swap customers and assets, relieving Sharyland’s ratepayers of some of the highest rates in the state. (See Texas PUC OKs Settlement in Oncor-Sharyland Asset Swap.)
Marquez singles out both Oncor proceedings as the proudest accomplishments during her tenure at the commission.
“[Sharyland’s] ratepayers were in a lot of pain out there. It became very important for me to find some kind of resolution, so people weren’t having to live in fear of their utility bill,” she said.
Marquez said she gained a deep appreciation for utility workers after visiting South Texas to see the restoration efforts following Harvey’s devastating blow to the Texas Gulf Coast last August.
“It’s an industry where when the rain is pouring down, [the workers] go out. In Houston, they wade in water up to their waist, and in South Texas, they’re in mud up to their knees. It’s very inspiring what these folks do to ensure we have the quality of life we have in this country.”
Marquez also had praise for the “problem-solvers” at the PUC — the staff, which she said provides a soft landing spot as the governor’s appointees cycle through. “They tell you, ‘Here’s what’s going on here. Don’t be afraid, we’ve got you,’” Marquez said. “We have a very good continuity plan, because we have a very good staff here.”
During last week’s open meeting, Walker noted that for the first time since 2008, official portraits of the current commissioners hang underneath the PUC’s logo on the meeting room’s wall. (Nelson did not allow her picture to be hung until just before she left last May).
“We’ll have three pictures up for one week. It’s your fault that we’re going back to two,” Walker said, teasingly.
Asked if she has any regrets about her decision, Marquez told RTO Insider that she leaves the PUC in good hands with Walker and Arthur D’Andrea, who replaced Nelson and Anderson, respectively, last fall.
“It’s a natural conclusion of a lot of things. It was the new energy of people who I could not think more highly of,” she said. “I just feel like it’s in a good spot, it’s an OK time for me to spring forward and see what kind of chaos I can get into.”
NEW ORLEANS — While MISO’s various sectors last week voiced differences in their views of what constitutes grid resilience, they could agree on one thing: Its specific attributes are still difficult to pin down.
Resilience was in the spotlight after MISO stakeholders selected the subject as their quarterly “hot topic” industry discussion held before the RTO’s Board of Directors on March 28.
Meeting participants offered a mixed bag of suggestions.
Minnesota Public Utilities Commissioner Matt Schuerger agreed with FERC’s definition of resilience as the “ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”
But Schuerger said he sees a lot of overlap between reliability and resilience, making the latter largely covered by NERC’s portfolio of standards.
Otter Tail Power’s Stacie Hebert said some of MISO’s transmission-owning members viewed resilience more narrowly as the ability of the system to recover from a failed state.
MISO’s Environmental sector is concerned about double-counting resilience as resource adequacy and reliability, said sector representative John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project. He argued instead that there are degrees between “fragile reliability” and “resilient reliability.”
“So much of what MISO already does in planning relates to resilience indirectly or directly,” Moore said.
Coal- and oil-fired generators became comparatively economic during early January’s cold snap because they had not been regularly run until emergency conditions nudged them “higher in the dispatch stack,” he said. “They were the most expensive resources in the system until we needed all resources.”
North Dakota Public Service Commissioner Julie Fedorchak said states may have to increasingly turn to MISO’s markets to fulfill generation requirements as uneconomic units retire.
Alliant Energy’s Mitchell Myhre said his Transmission-Dependent Utilities sector was trying to avoid being “too prescriptive” in defining resilience, a concept he called “hard to define.”
Still, others saw a clearer distinction between resilience and reliability.
“My kids will never know what it’s like to sit around with candles playing war games during a thunderstorm because the power is out. That just doesn’t happen anymore. That’s reliability,” Wisconsin Public Service Commissioner Mike Huebsch said. Resilience goes further than that, entailing better communication between grid operators, utilities and customers when disruptions occur, he said.
MISO Already Managing Resilience
Multiple members said MISO already has processes in place to tackle resilience.
“We think MISO is resilient. It’s always been part of our base business, even if we didn’t call it resilience,” said MISO Vice President of System Planning Jennifer Curran.
In response to FERC’s call for RTO/ISO comments on resilience in early March, MISO reported no “imminent or immediate” concerns in its footprint and pointed out that its stakeholder processes and projects have been geared toward resilience “for nearly two decades.” (See “MISO: Work Already in Progress,” RTO Resilience Filings Seek Time, More Gas Coordination.)
“The resilience issue is broader than the transmission grid, and we all have a role to play in ensuring resilience,” Curran told stakeholders.
Director Baljit Dail asked sectors what the RTO should do incrementally beyond what it already does.
“It seems to me that the bulk of the resilience issue is not at the MISO-level, but the distribution level, and that’s not MISO’s purview, but all of you sitting around this table,” he told members.
Moore said MISO could expand cybersecurity measures, with which Dail agreed.
Kevin Murray, representing the Coalition of Midwest Transmission Customers and MISO’s End-User Customers sector, pointed out that much of the RTO’s cybersecurity efforts can only be discussed in closed-session meetings to avoid release of sensitive information.
“I think one of the things that will be a challenge for us is sharing as much of that information as we can,” board Chair Michael Curran agreed.
Director Todd Raba said it seems the distinctions between transmission and distribution systems are becoming increasingly blurred. He rhetorically asked if MISO and its members have to reorganize the metrics placed on each system.
Schueguer said it will be a state-by-state choice to develop mandates to “harden” the distribution system.
‘Accidental’ Resilience
Independent Power Producers sector leader Barry Trayers said he thought MISO is heading toward resilience “almost accidentally” with increased distributed energy resources and a more diverse fuel mix.
“This movement towards DER should bolster the system because there’s less risk of a single large contingency,” said Director Thomas Rainwater.
The difference between the electrical recoveries from Hurricane Harvey in Texas and Hurricane Maria in Puerto Rico last year should help MISO and stakeholders define resilience attributes, Rainwater said. He pointed out that parts of Puerto Rico still don’t have power six months after the storm.
Murray pointed out that during hurricanes last year in Florida, bucket trucks and lineman were already queuing up before they hit, readying restoration efforts.
Director Mark Johnson said MISO and its members will at some point have to identify a list of the likely low-probability, high-impact events that could occur in the 15 states in its footprint, as well as the Canadian province of Manitoba.
“The actions that need to be taken will be very much event-specific,” Johnson said.
“There comes a point where maybe we put pen to paper or steel to ground,” agreed Advisory Committee Chair Audrey Penner.
Studying Weather Events
End-Use Customers sector representative and Louisiana Public Service Commission counsel Katherine King said a better understanding of resilience will require MISO to conduct an in-depth investigation into its South region’s two most recent maximum generation events: one last April after heavy outages and high temperatures, and another in mid-January triggered by extreme cold. (See “Several Factors in Spring MISO South Maximum Generation Event,” MISO Market Subcommittee Briefs and Louisiana Regulators Question MISO South Max Gen Event.)
“I think it’s very important to go back in after these events occur and ask what caused them and what we can do better,” King said.
The Louisiana PSC is opening a docket and scheduling a technical conference to investigate the January maximum generation event, King added.
Mississippi Public Service Commissioner Brandon Presley said the RTO should also study contingency impacts on the 3,000-MW contract path connecting MISO Midwest and South.
“Everybody has an interest in that connection and woe be it on us if we ignore that,” Presley said.
Rainwater said any changes made in the name of resilience must be cost-effective.
“At the end of the day, the end-use customers will have to pay for whatever resiliency measures we deem necessary, and we have to keep that in mind. We cannot build the system to protect it from … interruptions of any kind,” Rainwater said.
NEW ORLEANS — A seasonal post-mortem at MISO’s Board Week provided stakeholders with insight into the RTO’s market performance during the near past, near future — and beyond.
MISO and its Independent Market Monitor agreed that markets generally performed well during a challenging winter, and the RTO predicts more operational efficiency throughout spring. But it foresees considerable market changes over the next decade.
The RTO said the sustained cold snap that opened the year was “managed nearly routinely by MISO and members.”
Executive Director of Strategy Shawn McFarlane said the RTO’s $31/MWh December-February average energy price was about 10% higher than last winter.
MISO’s winter peak of 106.1 GW, set on Jan. 17, was 3.2 GW lower than its all-time winter peak set in January 2014. Loads exceeded 100 GW for the first five days of 2018, with forced and planned outages reaching 36 GW. (See MISO Breaks down Recent Cold Snap.)
“While it wasn’t routine, it was handled quite routinely — not a lot of excitement,” McFarlane said during a March 27 meeting of the Markets Committee of the Board of Directors.
MISO committed one unnecessary unit on Jan. 1, an inefficient outcome in what was an otherwise more efficient performance when compared to 2014’s polar vortex weather event.
However, the RTO said a brief mid-January cold spell concentrated in MISO South “proved more challenging, but reliability maintained.” During his quarterly report, Monitor David Patton agreed that mid-January generation patterns “were more fascinating.”
In that instance, another round of arctic air pushed loads above 106 GW over Jan. 17-18, and MISO South set a new winter peak of 32.1 GW in the face of record low temperatures in the region. (See Louisiana Regulators Question MISO South Max Gen Event.) MISO was forced to call a maximum generation event in the South region Jan. 17 after outages there hit 17 GW.
McFarlane said MISO South’s icy weather froze the region’s water and air lines, which are not nearly as insulated as in MISO Midwest. The RTO compensated for South’s shortfall with generation from Midwest, at one point flowing just over 3,000 MW — the maximum allowed by the MISO-SPP agreement — along the contract path between the regions.
“The [South] generators just aren’t as prepared for freezing temperatures,” Patton said. “Part of the reason we were in such bad shape is because the forced outages kept growing and growing. … This is about the most stressful situation I can imagine for MISO South.”
Patton said if the RTO had not made emergency power purchases for the South on Jan. 17, regional supply would have dipped below load for about three to four hours. He referred to the “lights going out in MISO South.”
But Director Michael Curran immediately rebuked Patton’s use of such dramatic language, while also responding that MISO should “burn down” SPP’s transmission on the contract path before it allows MISO South to shed load.
Patton said the situation highlights the need to create a regional capacity reserve product that can be delivered within 30 minutes, a recommendation he repeated from last year’s State of the Market report. He also said MISO’s emergency prices are still too low because its extended locational marginal pricing (ELMP) does not properly account for regional dispatch transfer flows. Accounting for such flows in ELMP would be an easy fix, he added.
Spring
Executive Director of System Operations Renuka Chatterjee reiterated a previous report of MISO’s spring preparedness but noted that volatile spring weather can “break load patterns.”
MISO staff said earlier in March that the RTO faces a small possibility of spring emergency conditions if either loads or forced outages are higher than normal. (See Outages Small Risk for MISO Spring Operations.)
Director Thomas Rainwater asked if the outage risk comes from large, thermal units whose loss “MISO has to scramble to replace.”
“Yes, it’s obviously the 1,000-MW units,” Chatterjee replied.
She said as little as an additional 2 GW in forced outages over forecasted load could force the RTO to call upon reserves this spring.
“We’ve seen a chance in the last couple of years of tight operating conditions in the shoulder seasons,” Chatterjee said. “[Reserves] are the end of our stack, and we’ll get into those if we have to.”
However, Chatterjee reassured the board that MISO faces a very slim chance of spring load shedding.
Patton said he now recommends that some generators take planned outages during winter rather than spring to lessen the impacts of mass outages in shoulder periods.
Beyond
With winter and spring covered, a MISO executive outlined a rough to-do list to design a market for a future grid that includes renewables, storage and smart devices.
Richard Doying, now head of future market design, delivered to the board the first report of his exploratory-style role. (See “MISO Shuffles Leadership,” MISO Informational Forum Briefs: Jan. 23, 2018.)
“MISO will be operating transmission with very different assets in the future,” he said.
Doying and MISO staff are evaluating what changes are needed to incorporate renewables, distributed energy supply and storage, and digital flow control devices such as smart appliances and thermostats. The RTO will complete an analysis of market, operational and planning impacts, and prepare a report by the first quarter of 2019, he said.
“Software cycle time really drives digitalization. When you think about an app on your phone that you can install today that wasn’t available yesterday — that took just a few weeks for someone to develop,” Doying said.
Digitalization will affect the grid much more than owners and operators may realize. “Although we can’t see when the changes will arrive, we know that they are coming,” he said. “Waiting until they arrive is a problem and will be imprudent.”
MISO must address, for instance, windy nights when LMPs fall to negative values, a situation that becomes unworkable for non-wind generators serving load. He also said the RTO’s market team will investigate how to properly value essential reliability services.
Director Baljit Dail asked what the RTO’s version of California’s “duck curve” may look like.
Doying responded that MISO is investigating a “double up” of its renewable sources in the next 10 to 15 years, as indicated by new entrants to the queue, but he didn’t elaborate on specific demand curve shapes.
“This is an exciting, but scary, pallet of issues,” said Director Barbara Krumsiek.
Rainwater asked how MISO will begin to value other attributes in a system designed around cost-based ratemaking.
Doying did not get into specifics, but he said that “pricing will be a critical element of any reforms.”
NEW ORLEANS — MISO’s dedicated market platform replacement team will work this year to ensure the RTO’s existing system can stay afloat during the time it will take to build the new one, staff told stakeholders last week.
While MISO is slated to begin naming specific requirements and assembling the new platform next year, this year’s efforts will focus on “standing up” the existing platform for day-to-day operations with software patches, Executive Director of Market Development Jeff Bladen told the Technology Committee of the Board of Directors on March 27.
The RTO has so far filled 18 of the 30 positions it has planned for this year, including market engineers and a software architect, Bladen said.
In 2017, MISO completed an assessment on the capability of its existing market platform and began early design of the new, more adaptable modular system. The RTO is poised to spend $130 million by 2024 to replace the aging system. It expects to begin migrating to the new system in 2020, keeping the current one in operation at least until 2021. (See MISO Makes Case for $130M Market Platform Upgrade.)
“This will be one of the largest undertakings in our history,” Bladen said.
“We’re making sure we build the right kind of system, not just an enhanced version of the current system,” MISO Director of Forward Operations Planning Kevin Sherd told stakeholders at a March Market Subcommittee meeting.
‘No BS’
With such a complex project, MISO’s directors urged that executives deliver clearer reports that do not minimize any future hitches or budget overflows.
“What I want to hear from you is clear, candid communication. No BS. No flowery language. … That’s the kind of stuff that I need to hear,” Director Thomas Rainwater told MISO executives.
“That’s what we need: full transparency and candor. We’re not going to rip your heads off,” Director Baljit Dail added.
Earlier in March, Bladen said the RTO’s new platform will be equipped to handle expanded energy storage participation under FERC’s Order 841, but the legacy system may struggle to accommodate the directives.
Meanwhile, MISO’s separate, settlements platform replacement is ready for the launch of five-minute settlements, officials said, although the RTO is continuing to test the new system while it waits for generation owners to adapt their own software and reporting systems to a five-minute schedule. MISO has twice obtained FERC approval to defer the five-minute settlements roll-out until July. (See MISO Wins Delay on 5-Minute Settlement Roll-Out.)
FirstEnergy Solutions filed for bankruptcy Saturday, two days after asking Energy Secretary Rick Perry to issue an emergency order directing PJM to compensate coal-fired and nuclear power plants that have 25 days of onsite fuel.
The request from FirstEnergy’s competitive power business came a day after the company announced that it will close its three nuclear plants — Davis-Besse and Perry in Ohio, and Beaver Valley in Pennsylvania — by 2021.
Davis Besse Plant NRC
Late Saturday night, the subsidiary filed for Chapter 11 protection in U.S. Bankruptcy Court in Akron, Ohio. The move has been expected since at least February, when FirstEnergy CEO Charles Jones predicted it in a company earnings call. (See FirstEnergy CEO Predicts Death of FES, Coal, Nuclear.)
In a statement, FirstEnergy made clear that the bankruptcy proceedings only applied to FES and its subsidiaries, including FirstEnergy Nuclear Operating Co. Jones touted the move as part of the company’s strategy to get out of the competitive power industry.
“Becoming a fully regulated utility company should give FirstEnergy a stronger balance sheet, solid cash flows and more predictable earnings. Simply put, we will be better positioned to deliver on the tremendous opportunities for customer-focused growth,” he said.
According to Bloomberg, FES is about $3.6 billion in debt, of which 60% is in municipal bonds. It had faced an April 2 deadline to pay bond holders $100 million.
‘Immediate Action’ Requested
In its 44-page letter to Secretary Perry, FES said the premature retirements of its three plants, along with other coal and nuclear plants in PJM, constitute an emergency threat to the reliability of the RTO’s grid. It cited as evidence a report released just two days earlier by the Department of Energy’s National Energy Technology Laboratory that said coal “provided the most resilient form of generation in PJM” during the January cold snap known as the “bomb cyclone.”
“PJM continues to claim that all is well with its system, but at the same time shows it does not have a clear view of what resilience is, how to measure it or how to ensure it,” FES told Perry. “PJM has demonstrated little urgency to remedy this problem any time soon — so immediate action by the secretary is needed to alleviate the present emergency.”
Beaver Valley Plant
PJM rejected FES’ allegation. “This is not an issue of reliability,” PJM said in an emailed statement. “There is no immediate emergency.”
FES also criticized FERC for rejecting DOE’s Notice of Proposed Rulemaking that would have directed all RTOs and ISOs to compensate the full operating costs of any generating facility with 90 days of onsite fuel. The commission instead opened a new docket to receive input on the resilience issue. (See RTO Resilience Filings Seek Time, More Gas Coordination.)
“Despite the fact that the time for such remedial action has come, FERC terminated your rulemaking proceeding and chose instead merely to study the issue further,” the company wrote. “FERC’s response was disappointing. FERC’s reliance on comments by RTOs/ISOs — the very entities that preside over the flawed markets — is misplaced. More fundamentally, FERC’s decision to study the issue further is too little, too late.”
FERC recently extended the deadline to May 9 for intervenors to submit comments in response to the grid operators’ filings (AD18-7).
FPA Section 202c
FES’ requested order, which would be invoked under Section 202c of the Federal Power Act, would apply to “nuclear and coal-fired generators located within the PJM footprint that have a supply of fuel on site sufficient to allow 25 days of operation at full output; that are substantially compliant with all applicable federal, state and local environmental laws and regulations; and that do not recover any of their capital or operating costs through rates regulated by a duly authorized state regulatory authority, municipal government or energy cooperative.”
Those plants would “be compensated with just and reasonable rates that provide for full recovery of its fully allocated costs and a fair return on equity.”
FES also requested that in cases when PJM and a qualifying plant are unable to reach an agreement on rates, “the secretary step in and determine the just and reasonable compensation and conditions.” It also asked that the order remain in effect for at least four years or “until the secretary determines that the emergency has ceased to exist because the PJM markets have been fixed to properly compensate these units for the resiliency and reliability benefits that they provide.”
The Energy Department has used its authority to declare emergencies eight times since 1977 — when the Department of Energy Organization Act transferred this power from FERC to the secretary of energy — beginning with the Western Energy Crisis of 2000. Perry has invoked it twice: last April for the Oklahoma-owned Grand River Dam Authority’s Grand River Energy Center Unit 1, and in June for Dominion Energy’s Yorktown plant. (See DOE Approves Emergency Dispatch of Yorktown Units.)
In both cases, the plants were coal-fired. And in both, Perry issued the orders less than five days after receiving the requests from the plants’ owners. In Yorktown’s case, PJM had also filed a request.
Section 202c limits any emergency action to 90 days if it conflicts with any other law, although it allows the secretary to extend the emergency for another 90 days after a review. Perry has renewed the Yorktown request twice, as PJM had requested that it stay in effect until the construction of a needed transmission line in the Historic Triangle region of Virginia.
However, FES said that “because the eligible nuclear and coal-fired generators must continue to substantially comply with all applicable federal, state and local environmental laws and regulations, the provision in Section 202c limiting the duration to a 90-day period is not applicable.”
Robert Murray, CEO of coal producer Murray Energy, has been lobbying the Trump administration to issue an emergency order for FirstEnergy’s Ohio coal plants, his company’s biggest customer, since at least last July. Perry had reportedly rejected the use of such an order in August, opting instead to issue the resilience NOPR. (See Photos Show Murray’s Role in Perry Coal NOPR.)
Bloomberg, citing anonymous sources, reported in February that DOE officials were still considering the use of 202c for FirstEnergy’s coal plants, but the department countered that the sources were “misinformed.” Nevertheless, Undersecretary Mark Menezes told Bloomberg that “we have authorities that we can use when the need arises. They’re well known. And we’ll use them if we need to.”
PJM, Stakeholders React
PJM acknowledged fuel supply diversity is important. “But the PJM system has adequate power supplies and healthy reserves in operation today, and resources are more diverse than they have ever been. Nothing we have seen to date indicates that an emergency would result from the generator retirements,” the RTO said. “The potential for the retirements has been discussed publicly for some time. In anticipation, PJM took a preliminary look at the effect of the retirements on the system. We found that the system would remain reliable. We have adequate amounts of generation available.”
In February, PJM issued a report showing that its grid performed reliably during the cold snap but that price formation changes were needed, echoing comments that CEO Andy Ott made in January before the Senate Energy and Natural Resources Committee. (See PJM: Cold Snap Uplift Shows Need for Pricing Changes.)
Condemnation of FES’ request was widespread across stakeholder sectors and interests.
“FirstEnergy does not speak for its own customers, as strong opposition from their customers to past FirstEnergy bailout attempts clearly shows, much less their attempt to speak for all 65 million customers who depend on PJM,” the Electric Power Supply Association said. “Similarly, FirstEnergy does not speak for all other coal and nuclear asset owners.”
On Friday, EPSA joined with 10 other trade associations — the American Council on Renewable Energy, American Forest & Paper Association, American Petroleum Institute, American Wind Energy Association, Electricity Consumers Resource Council, Independent Petroleum Association of America, Interstate Natural Gas Association of America, Natural Gas Supply Association, Solar Energy Industries Association and Advanced Energy Economy — to request that Perry allow comment on FES’ filing, citing the company’s failure to seek rehearing of FERC’s decision on the resilience NOPR.
“It would be manifestly unreasonable and unfair to both other interested parties and the secretary for FE Solutions to demand that the secretary act without hearing from interested parties, including PJM, after having failed to exercise its right to request rehearing before FERC and waited nearly three months before challenging FERC’s order through the March 29 request to the secretary,” the groups said.
The Sierra Club said a 202c order would be illegal and promised to sue the department if Perry granted FES’ request. “If the Trump administration bows to FirstEnergy and moves forward with this bailout attempt, Sierra Club fully intends to challenge and defeat the administration in court,” said Mary Anne Hitt, director of the group’s Beyond Coal campaign.
NRG Energy spokesman David Gaier called FES’ request “a solution in search of a problem.”
“The only crisis here is one affecting FirstEnergy’s shareholders, and Ohio ratepayers should not be asked to bail out FE for its inability to profitably operate its power plants,” Gaier said.
John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project, said, “FirstEnergy is desperate to pad its bottom line at the expense of its customers. The region is awash in cleaner and cheaper resources, and FirstEnergy can’t compete in the market. This move is stunning given that the Federal Energy Regulatory Commission, the Department of Energy and the state of Ohio have all rejected these bailouts.”
“PJM has twice the reserve margin it needs so this fuel supply crisis is completely manufactured,” said Rob Gramlich, president of Grid Strategies, a renewable energy consultancy. “PJM has been quite accommodating in my opinion, asking FERC for a nationwide ruling and to be directed to make market design changes if they deem necessary. They’re punishing some pretty good deeds.”
While the Nuclear Energy Institute lamented the plant closures, it did not express direct support for FES’ request.
“The announcement from FirstEnergy to retire more than 4,000 MW of nuclear power generation demonstrates the urgency for policymakers to act before it is too late,” said John Kotek, NEI vice president of policy development and public affairs. “All options to prevent the closure of nuclear plants should be explored.”
Nuke Closures
In Wednesday’s announcement of the nuclear plant closures, FES Generation President Don Moul repeated its call for “elected officials in Ohio and Pennsylvania to consider policy solutions that would recognize the importance of these facilities to the employees and local economies in which they operate, and the unique role they play in providing reliable, zero-emission electric power for consumers in both states.”
Zero-emission credit legislation similar to that passed in Illinois and New York has stalled in Ohio, however.
Perry Nuclear Plant | Wainstead
The plants have a combined capacity of slightly more than 4 GW, representing about 65% of the electricity FES generated in 2017, according to the company.
“PJM has an established 90-day process to review generator retirement requests. We will conduct the full analysis required to determine if there would be any local effects on the grid,” the RTO said in its statement. “However, given the unusually long advance notice, there would be sufficient time to complete any transmission upgrades required.”
It also noted there are about 10 GW of generation in Ohio under construction or in the interconnection queue.
FERC on Thursday accepted the recommendations of SPP’s Market Monitoring Unit to eliminate the Woodward frequently constrained area (FCA) in Northwest Oklahoma and replace the Texas Panhandle FCA with a smaller one for the Lubbock area. The changes are effective April 1 (ER18-736).
FCAs are areas with high levels of congestion that are also subject to one or more pivotal suppliers.
The Monitor’s December 2017 FCA report recommended removing the two historically congested areas that appeared on the 2016 report, while designating one new FCA. The MMU annually reviews and designates SPP’s congested areas.
| SPP
The MMU recommended removing the Woodward FCA — added in January 2016 because of the growth in wind resources in western SPP — because of a decrease in congestion following the Woodward phase shifting transformer upgrade in May 2017.
It said the Texas Panhandle FCA should be removed because it no longer met the threshold of binding for at least 500 hours with a $25/MWh impact during a given 12-month period.
However, the Monitor suggested the Lubbock, Texas, area be added as SPP’s lone FCA for this year. The area first appeared as an FCA candidate in the 2015 study and has seen increased congestion since, indicating a shift in congestion south of the Texas Panhandle, the MMU said.
SPP’s FCA Candidate Areas | SPP
Congestion in this area was part of the southern section of the Texas Panhandle FCA but upgrades north of the Lubbock area and the Woodward-Border-Tuco 345-kV line shifted the congestion to the southwestern edge of the RTO’s grid.
“The Texas Panhandle still sees congestion, but the addition of the Lubbock area better represents where the concern of exercise of market power exists,” the MMU said. The Lubbock area saw 686 hours of congestion in 2017.
FERC ruled that the Monitor’s suggestion that it simply post the FCA list on SPP’s website without the Board of Directors’ approval was outside the proceeding’s scope. The MMU said that following the Tariff requirement for board approval can take six months, a lag that can lead to outdated FCA lists and that “does not allow SPP or the Market Monitor to efficiently and appropriately address market power concerns.”
The commission urged the RTO and its stakeholders to consider the MMU’s suggested improvements to the FCA re-evaluation and designation process through the stakeholder process.
FERC last week approved SPP’s proposed Tariff revisions reducing network service charges for customers in Southwestern Power Administration’s (SWPA) pricing zone, effective April 1 (ER18-769).
The commission agreed with SPP that the proposed revisions, filed in January, will ensure SWPA customers are not charged twice for the same deliveries. FERC noted it had previously accepted similar mechanisms to eliminate double charging for deliveries of statutory hydropower obligations to federal preference customers.
SWPA is one of several Department of Energy power marketing administrations selling hydroelectric power produced at Army Corps of Engineers dams “with preference to public bodies such as rural electric cooperatives and municipal utilities.” The agency participates in SPP as a limited transmission owner under the RTO’s Tariff, selling excess transmission capacity on its system as non-federal transmission service under grandfathered agreements with individual customers or through its Tariff.
SPP uses SWPA’s transmission facilities, located in pricing Zone 10, to provide transmission service, scheduling services, operating reserve sharing, reliability coordination and other services. Attachment AD of the RTO’s Tariff “contemplates” the migration of all non-federal transmission service customers to network service or point-to-point transmission service, FERC said.
SWPA recovery crew pauses during 2009 restoration work | Southwestern Power Administration
SPP explained to the commission that network service customers in SWPA’s pricing zone are assessed monthly demand charges on a coincidental peak basis under Schedule 9 of the Tariff, based on the customer’s total metered load. Because SWPA charges a bundled rate for deliveries of its federal power, federal preference customers could pay twice if they take SPP network service in the zone and do not use any other TOs’ intervening facilities, the RTO said.
SPP said the revisions would eliminate the double charging by reducing the eligible network customers’ network load by the amount of federal power they receive from SWPA, scheduled at the time of the coincident peak used in calculating Schedule 9 demand charges.
The commission noted SWPA recognized the double charging issue and sponsored the Tariff revision through SPP’s stakeholder process. The SPP Board of Directors approved the change in July 2017.
