MISO on Wednesday revealed plans to rely more heavily on its own load forecasting to support long-term transmission planning, instead of primarily drawing on a combination of forecasts provided by load-serving entities.
Stakeholders were unenthusiastic about the idea, which would elevate the role of an independent long-term forecast provided by Purdue University’s State Utility Forecasting Group. MISO says stakeholder input will influence a second version of the proposal presented in December.
Under its existing planning process, MISO draws on an aggregate of about 150 LSE resource adequacy forecasts submitted under Tariff Module E to inform economic studies for its annual Transmission Expansion Plan. The LSEs currently provide 24 months of load forecasts and produce additional predictions for eight seasonal peaks to create a 10-year forecast. The RTO uses the data to extrapolate another 10 years into the future to fit its 20-year planning horizon.
MISO planning horizon with use of an independent load forecast | MISO
MISO also consults the Purdue forecast — which relies on 20-year forecasts produced by states — but only to draw comparisons with the LSEs’ predicted growth rates. The RTO earlier this year said it was investigating ways to improve that independent forecast. (See Dynegy: MISO LSE Load Forecasts Require Tune-up.)
Blending Forecasts
Konidena | MISO
MISO is now proposing to blend the LSE and Purdue forecasts, adviser Rao Konidena said during an Oct. 18 Planning Advisory Committee meeting. Under the new approach, it would no longer extrapolate the LSEs’ predictions, instead relying on Purdue’s forecasts to predict growth rates for the second half of the planning horizon.
The RTO said it planned to use the independent forecast in part because it does not know what economic drivers underpin the LSEs’ forecasts or whether the LSEs include state renewable or efficiency mandates and emissions goals. Use of both forecasting methods will lead to “better evaluation of impacts of variations in assumed penetration levels of demand response resources, energy efficiency, and distributed energy resources,” it said.
Adam McKinnie, an economist with the Missouri Public Service Commission, asked whether MISO had faith that utilities were making thoroughly researched predictions of future load growth with their state-submitted resource adequacy plans.
“Do you ask utilities for the drivers of economic growth behind their load forecasts?” McKinnie asked. “You seem to be taking shots at the Module E forecasting,” he added.
“All I’m saying is that I don’t know what goes into the economic drivers,” Konidena responded.
Minnesota Public Utilities Commission staff member Hwikwon Ham wondered if MISO thinks it’s overbuilding or underbuilding transmission based on the use of its existing Module E process. “You have to show that there is a better process,” he said.
Konidena stressed that MISO only wants to use a forecast that’s designed with the next 20 years in mind, rather than simply extrapolating a 10-year forecast. Use of two separate forecasts for the same planning studies will lower the risk of load forecast miscalculations being compounded into “poor year-out projections,” he said. MISO has also noted that Applied Energy Group predicts that demand-side management programs will hit a saturation point in a decade, something the RTO will fail to include in its growth rate if it simply extrapolates aggregated utility forecasts.
Real Projects, Real Money
Indianapolis Power and Light’s Lin Franks said that the sample coincident peak produced by the blend is too aggressively high: It results in a 150-GW summer coincident peak by 2035, about 5 GW higher than if MISO relied on a Module E extrapolation alone.
“I’m worried about this. This is real money. These are real projects that people are going to want to build, and when we get there, those transmission lines are going to be empty,” Franks said.
WPPI Energy’s Steve Leovy says his company already forecasts 20 years in advance and said he’d be happy to share the longer forecasts with MISO.
Konidena asked stakeholders to submit suggestions on the blended approach by Nov. 17. He said MISO would continue discussing possible expanded used of the independent load forecast at the December PAC meeting.
“You’ve asked if stakeholders have ideas on how to blend the forecasts, to provide them. If we have ideas about not blending them, are you open to that too?” asked Entergy’s Yarrow Etheredge, eliciting laughter.
Konidena said he was open to such suggestions if stakeholders could make a business case for keeping the forecasts separate.
FERC last week rejected a request to rehear its October 2016 ruling requiring MISO to revise its interconnection fees, saying the treatment of external generator Manitoba Hydro was beyond the scope of the order (EL16-12-002, et al.).
The commission had ordered MISO to apply milestone payments equally across all classes of customers, prompting the American Wind Energy Association (AWEA) and Wind on the Wires (WOW) to question how the RTO is processing 3,500 MW of external generation from Manitoba Hydro. The wind advocates claimed sales of Manitoba Hydro’s generation were allowed onto the system under a firm transmission service right, thus circumventing milestone payments.
| Manitoba Hydro
The arrangement equated to preferential treatment, the two said, and asked FERC to determine under what Tariff provision MISO allows Manitoba Hydro sales. They said Exelon’s 3,500 MW of external generation is processed under interconnection service and external network resource interconnection service (E-NRIS), which now requires milestone payments.
In rejecting the rehearing request Thursday, FERC said AWEA and WOW could raise their concerns in MISO’s stakeholder process or submit a fresh complaint to the commission.
The commission said last year’s order centered on which classes of interconnection customers must make milestone payments and is not focused on an “overbroad interpretation” of the “terms and conditions of transmission service in specific transactions involving MISO and Manitoba Hydro, which are outside the scope of this proceeding.”
The October 2016 order stemmed from a complaint by a group of internal MISO generators who contested the RTO’s practice of exempting external generating resources from paying a significant fee levied on any new internal resources seeking to enter the final stage of the interconnection process. (See FERC Orders MISO to Levy Interconnection Fees Equally.) At the outset of the definitive planning phase, new MISO interconnection customers within the footprint must make an M2 milestone payment to fund impact studies and cost analysis. MISO had waived the fee for both new and existing generators outside its footprint under the assumption that those resources have already established interconnection agreements within their own balancing areas.
MISO applied the new rules required by last year’s order to two service agreements: 30 MW of E-NRIS from Exelon’s Fairless Hills Power Plant in Pennsylvania and 2,300 MW of E-NRIS from Exelon’s Byron Nuclear Facility in Illinois (ER17-1000, ER17-1013). FERC accepted both on Thursday.
AWEA and WOW had protested acceptance of the service agreements, arguing that Manitoba’s large external service agreement earned a 147-page reliability study result from MISO, and an analysis of Exelon’s external generation only yielded an 18-page result. The two said the reports contained “insufficient data to confirm MISO’s conclusion that there are no reliability and deliverability violations and that no network upgrades are needed to accommodate the new 2,330 MW.” FERC said the claims were unsubstantiated.
LITTLE ROCK, Ark. — SPP said Thursday it will join the ISO/RTO Council’s (IRC) filing against the Department of Energy’s Notice of Proposed Rulemaking to support struggling coal and nuclear plants, pointing to what staff called “some pretty strong comments.”
“The council does a really good job of laying out why this doesn’t work from an RTO perspective,” SPP General Counsel Paul Suskie told the Strategic Planning Committee.
Initial comments on the NOPR (RM18-1) are due at FERC by Monday as part of a compressed 90-day timeline that has drawn industry-wide criticism. DOE’s proposal requires that generators with 90 days of on-site fuel supply receive “full recovery” of their costs. (See Perry Orders FERC Rescue of Nukes, Coal.)
Suskie told the committee the IRC’s comments contend the timeline is not practical, that FERC is already addressing many of the issues with its price-formation directives and that the DOE proposal will only make the electric markets worse.
“If you’re a plant under the rule, your costs are totally covered,” Suskie said. “Why would you do anything but bid zero into the market? It will drive costs down further and distort markets further.”
Some stakeholders expressed discomfort with signing onto the IRC comments without seeing the language.
“The basic issue here is the subsidy,” countered SPP Board Chair Jim Eckelberger, saying renewable energy tax credits had led to oversupply. “We don’t want to screw up the market even more. We should take a strong stand here.”
Staff will also file comments raising issues and seeking clarifications on the NOPR’s language. Separately, SPP’s Market Monitoring Unit will file its own comments.
In its call for comments, FERC said the NOPR’s scope applies to commission-approved ISOs and RTOs with capacity markets and day-ahead and real-time energy markets. Noting SPP’s lack of a capacity market, Suskie said while it “appears this rule is not applicable to SPP,” staff will work under the assumption that a final FERC rule could apply to the RTO.
Suskie said staff will develop further comments for the reply comments, due Nov. 7. The comments will note SPP operates in states with vertically integrated utilities, where capacity is provided by regulatory constructs, and that the 90-day timeline is “impractical.”
“Staff would recommend additional time to implement if the final rule applies to SPP,” Suskie said, noting staff would have to compile a list of eligible facilities. “Staff is very concerned. … If you read what the intent appears to be, basically any coal or nuclear plant not [rate-based] within an RTO would have to be fully compensated.”
Suskie asked who would determine a plant’s rate of return and cost of capital.
“Traditionally, those things are decided at the commissions, not RTOs,” he said. “How do you enforce a 90-day coal supply? How do you enforce whether a plant complies with environmental regulations?
“If this is applicable to SPP, it would be a big sea change,” Suskie said.
Keith Collins, executive director of SPP’s MMU, said his group agrees with much of what Suskie said, saying the NOPR is “proposing a solution to a problem that’s not well defined.”
The NOPR “doesn’t define the problem well in a way that’s actionable and measurable,” Collins said. “When you actually read the [recent DOE grid study], it says more work needs to be done to value and define resiliency before you come up with solutions. What’s included, what’s excluded … it’s hard to say.”
Like Suskie, Collins said the 90-day timeline does not allow sufficient time to properly consider the NOPR.
“If there’s a question to be raised, it can be answered over time, but we don’t support what’s going on,” he said. “Competitive forces have been part of policy in the energy and electricity markets over the last 25 years. It will provide new technologies, batteries and the like, that will improve the resiliency for the grid in ways we’re not aware of today.
“What the Energy Policy Act of 1992 did was promote competitive markets and open access,” Collins said. “If someone can provide power cheaper than someone else, they should be able to do that. If I built a plant a while ago that’s unprofitable, that’s a signal. Resources are indicating they are not being able to recover their costs. We see the consequences of a policy like this with our negative pricing.”
FERC on Thursday ordered Federal Power Act Section 206 proceedings for five SPP transmission owners seeking to develop projects under the RTO’s Order 1000 competitive solicitation process.
The commission accepted revised formula rate templates and protocols for ATX Southwest (ER15-1809-001, EL18-12); Transource Kansas (ER15-958-003, EL18-13, ER15-958-004); Midwest Power Transmission Arkansas (ER15-2236-001, EL18-14); and Kanstar Transmission (ER15-2237-001, EL18-15, ER15-2237-003). But the commission ordered 206 proceedings because the companies’ filings did not provide for inclusion in their annual updates sufficient descriptions and justifications for the allocation of costs between them and their affiliates.
| SPP
FERC also set a 206 proceeding for South Central MCN, saying its revised protocols “attempt to define the scope of future filings” under FPA Section 205 (ER15-2594-003, ER17-953, EL18-16). The commission said South Central had provided an adequate description of its cost allocation methodology as required by an order in October 2015.
FERC said Thursday it will let MISO and SPP work with their stakeholders to determine whether the RTOs should require refund commitments from their transmission-owning nonpublic utility members.
In agreeing to hold in abeyance Section 206 proceedings on the issue, FERC ordered the RTOs to file proposals by Feb. 28, 2018 (EL16-91, EL16-99). FERC additionally required them to submit reports updating the status of their endeavors by Dec. 15.
The commission, however, rejected claims by MISO, electric cooperatives and nonpublic utilities that it lacked the authority to order changes in the RTOs’ governing documents to require refund commitments. While the Federal Power Act explicitly limits FERC’s jurisdiction to public utilities — a limitation the commission had acknowledged in its July 2016 order initiating the 206 proceedings — the co-ops argued that the commission’s actions amounted to a “work around,” or an indirect order. (See Co-ops, MISO, SPP Urge FERC Restraint with Nonpublic Utilities.)
Rural Electric Cooperative line workers in Oklahoma | Rural Electric Cooperative
Citing federal court rulings, FERC reasserted that once a nonpublic utility’s transmission revenue requirement becomes a component of an RTO’s rates, the commission can “‘analyze and consider the rates of [nonpublic] utilities to the extent that those rates affect jurisdictional transactions’ through their inclusion in the RTO’s rates.”
“The proposal as laid out in the July 2016 order gives nonpublic utility transmission owning members the choice to leave SPP if SPP membership is no longer financially advantageous,” FERC said, using identical language in its order regarding MISO. “The commission is, however, under no obligation to permit nonpublic utilities that choose to become members of SPP and to recover revenues through the SPP Tariff to collect unjust and unreasonable rates through an RTO’s jurisdictional tariff without any consequence.
“We acknowledge … that we lack the statutory authority to order nonpublic utility transmission owners to make refunds. Instead, the refund commitment would serve as a condition precedent for nonpublic utility transmission-owning members to recover revenues through the SPP Tariff associated with service provided due to their status as transmission-owning RTO members and based on a choice they made to become members.”
WASHINGTON — Arnie Quinn, director of FERC’s Office of Energy Policy and Innovation, had modest hopes for reaching consensus when he moderated a panel on public policy and wholesale markets at the Energy Bar Association’s Mid-Year Energy Forum last week.
The panel included Exelon’s Kathleen Barron, a defender of zero-emission credits for nuclear plants, and NRG Energy’s Peter Fuller, whose company is a harsh critic of the subsidies.
“While I think it might be hard to come up with a consensus about what ultimate landing spot we’d like to get to … at least agreeing on what we’d like to avoid would be helpful,” Quinn said.
Quinn also invoked one unsafe word for the discussion: “MOPR” — minimum offer price rule. “Unfortunately, we’ve got a lot of pending dockets on minimum offer price rules,” Quinn explained.
MOPR was not invoked. But consensus was indeed elusive in the discussion, which included FERC’s May 1-2 technical conference on state policies and wholesale markers and Energy Secretary Rick Perry’s call for price supports for nuclear and coal plants.
Barron, Exelon’s senior vice president for competitive market policy, defended the ZECs approved in New York and Illinois, saying they had a “quite modest” impact on wholesale markets compared to state renewable energy credits and rate-based generation.
“I think we need to take a step back when we launch this conversation to just recognize that even the Eastern markets are not free of intervention,” she said. “By 2025, about 30% of the generation in PJM will either be rate-based — through state cost-of-service regulation — public power or [renewable portfolio standard] programs,” she said.
Even if all of PJM’s nuclear generation — currently 19% of the RTO’s capacity mix — were subsidized, she said, it would still have a smaller impact than state RPS goals. “How many renewable resources would they like to have?” she asked. “25%, 30%, 50% by 2030?”
Moreover, while ZECs are worth $17.54/MWh in New York, that is less than the state’s RECs, which run as high as $23.28, she said. Illinois’ ZECs are $16.50/MWh, while their solar RECs are worth more than $200/MWh. And Maryland will pay $132/MWh for offshore wind RECs. “So we’re talking about relatively small amounts compared to other clean generation programs,” she said of ZECs.
Despite his company’s opposition to ZECs, Fuller did not contest Barron’s claims. Instead he chose to discuss his company’s “four product” vision of the future: renewables, energy storage, controllable demand and fast-ramping gas.
Fuller said that the Department of Energy’s Notice of Proposed Rulemaking had sparked an “extremely important conversation” and that a role for fuel security is an “option to think about.”
But he added, “The solution set, I think, is much broader than what was in the original notice from DOE.”
In a future dominated by zero- or low-marginal cost future, the LMP markets based on fuel costs “breaks down,” he said. “Are we doing locational marginal pricing right? Are we calculating energy prices right? PJM has a proposal to really look at different eligibility for setting energy prices. That would be an important idea. Clearly we need scarcity pricing everywhere to capture the operational realities of the markets.”
Fuller was the only member of the panel — which included Rob Gramlich, of Grid Strategies, and Potomac Economics’ David Patton, whose firm performs market monitoring for MISO, NYISO, ERCOT and ISO-NE — who did not have FERC tenure on his resume.
‘Wacky’ Federal Initiatives and RTO ‘Mission Creep’
Gramlich, a former senior vice president for government and public affairs for the American Wind Energy Association who now consults for AWEA and other clean energy interests, said the DOE NOPR would “upend 25 years of progress toward competitive markets.”
“We’ve had this conversation many times,” said Gramlich who served as senior economic adviser to FERC Chairman Pat Wood III in 2001-2005. “I think there’s one major thing that’s changed from the previous [discussions]. Usually the context is the wise, well intentioned federal authorities or the RTOs trying to clean up or fix what the wacky states are doing. [Now we’re considering] not only wacky state policies but wacky federal policies and see whether we have a regulatory structure that can withstand that,” he said, sparking laughter. “You might say whether it’s resilient, whether it can withstand and bounce back rapidly from narrow political interventions.”
Gramlich said market interventions have caused “mission creep” for RTOs beyond their traditional roles of running the transmission system and wholesale markets. “I’m frankly concerned that the RTO missions are getting extended well beyond those two core things and that a lot of states and utilities will look at these RTOs and say, ‘I’m out.’ Or, ‘I’m in the West and I was thinking of joining. Now I’m not.’”
Gramlich was skeptical of Perry’s call for compensating generation units for having on-site fuel supplies or providing “essential reliability services.”
“We’re seeing all sorts of interests saying their product or their generation type provides this, that or the other thing to the grid. I’m really relying on FERC here to decide: Is that actually needed? Is that actually a service? And if so, can others provide it as well? And let’s create real competitive markets: define the service and then let any and all bidders bid to provide that service.”
Patton said policymakers face an existential question. “You either believe in markets or not. And if you don’t believe in markets then why are we doing this?” he asked.
“This just becomes a giant rent-seeking exercise. I know when I say that to a room full of lawyers, that doesn’t sound terrible,” he added to laughter.
Patton said FERC deserves blame because it has “never articulated any sort of standard on what a just and reasonable capacity market looks like. The closest they’ve ever come is in New York, saying it’s got to produce a price signal that will be sufficient to get an adequate resource mix.”
He noted that capacity markets incent generation investments that are evaluated over a lifespan of 30 or 40 years.
“If every year or two you have dramatic policy shifts that change fundamentally what people’s expectations are about the market revenues they’re going to get, then you get … the worst-case scenario.
“It’s alarming how many times … new [FERC] commissioners have come in and said, ‘I want to revisit whether capacity markets are a good idea. Let’s have a technical conference and determine whether capacity markets are delivering on their objectives.’ Basically, the subtext is we may do away with these things. And they’re delivering roughly half the revenue that the generation needs to break even on a new investment. … It’s like when Congress says, ‘We may not raise the debt ceiling.’ How do you even say that?”
Patton disputed arguments Perry and others have made in defense of price supports.
“When people tell me we’re overly gas-dependent, we don’t have markets that value fuel diversity, [I say] that’s absolutely not true. When people say we don’t have a market that motivates generators to be available and perform, that’s absolutely not true,” he said. “They’re assertions that support doing something and changing the markets. But if you think about what we’re talking about, if you have good shortage pricing and we’re short somewhere because a gas pipeline blew up, then everybody who’s got dual-fuel capability [or is] powered by something other than gas makes an enormous amount of money. Anyone who’s gas-only and didn’t make provisions to be able to run in that scenario loses a lot of money, especially under the New England [Pay-for-]Performance rules that overcompensate performance.”
Patton said the NOPR’s notion of “‘resilience’ is just reliability” for contingencies whose probabilities are so low that grid operators haven’t planned for it.
“And if it happens, our shortage pricing is going to account for it,” he said. “The overriding objective should be to maintain market signals, and there’s only a few of them: There’s energy, ancillary services and capacity. You don’t need 10 products to do that.”
MISO and PJM have withdrawn their support for developing the lone interregional market efficiency project to emerge from the RTOs’ two-year coordinated system plan, stakeholders learned Friday.
The proposed 30-mile, 138-kV line between Northern Indiana Public Service Co.’s Thayer and Morrison substations near the Indiana-Illinois border was expected to cost $61.8 million and be in service by December 2022. NIPSCO’s early estimates pegged the cost at $42.5 million. (See “MISO-PJM Coordinated System Plan Produces One Project,” FERC Conditionally OKs MISO-PJM Targeted Project Plan.)
| MISO and PJM
The project was the only one of eight stakeholder-originated suggestions to initially pass the RTOs’ benefit-cost criteria, but it ultimately failed a joint 5% generation-to-load-distribution factor (GLDF) test, which requires each RTO to show that one of its generators has at least a 5% impact on the affected flowgate. PJM did not meet the threshold.
During an Oct. 20 Interregional Planning Stakeholder Advisory Committee conference call, NIPSCO’s Matt Holtz said the addition of the GLDF test essentially equates to a joint benefit test that FERC ordered the RTOs to eliminate from their “triple hurdle,” which included their separate regional benefit tests. He expressed disappointment that both RTOs would withdraw support from the project when “just using the regional processes showed a lot of economic benefit to MISO and PJM.”
“I’m not sure that we would agree with that analysis,” PJM engineer Alex Worcester responded. “I’m not sure that each RTO’s impact on the model ties to a triple hurdle.”
“The 5% criteria has long been in the [joint operating agreement],” said Chuck Liebold, PJM manager of interregional planning.
Another PJM stakeholder said the GLDF test amounted to a “technicality.” Worcester said PJM is open to examining its test requirement.
To address congestion in the area, local transmission owner Ameren upgraded its transmission ratings, resulting in congestion being shifted away from a nearby 138-kV line to another line in the PJM footprint, Worcester said. The updated ratings cleared up congestion on the PJM side of the seam, compelling the RTO to withdraw its recommendation for the project based on its regional analysis, even if the GDLF test wasn’t an issue.
Wind on the Wires’ Rhonda Peters asked for the reason behind the change in rating to the line.
“We can’t always be perfectly coordinated,” Worcester said, adding that he didn’t know why Ameren upgraded the rating. MISO interregional coordinator Adam Solomon said his RTO could investigate the change.
Worcester said MISO could pursue the Thayer-Morrison project in its separate process. MISO has said it may consider the project for its annual Market Congestion Planning Study next year.
The RTOs’ next interregional market efficiency project proposal window required under FERC Order 1000 opens in November 2018. Stakeholders have until February 2019 to submit project suggestions.
In the meantime, Solomon said both MISO and PJM staff would work together on ways to improve the process behind their coordinated system plan.
FERC last week accepted NYISO’s proposed Tariff changes establishing a mechanism to recover costs for eligible transmission projects in the ISO’s Comprehensive System Planning Process.
The commission’s order accepted revisions to section 6.10 (Rate Schedule 10) and Attachment Y of NYISO’s Tariff effective Oct. 18 (ER17-2327).
NYISO submitted the proposed revisions in August, arguing that since the commission approved the current Rate Schedule 10 in 2008, it has instituted new planning procedures that created gaps in its ability to fairly allocate transmission cost recovery.
The grid operator said the proposed Tariff revisions would “enhance and expand the applicability of Rate Schedule 10, so that it can be used for all regulated transmission projects in any of the three planning processes (i.e., reliability, economic and public policy-driven.”
The tariff changes replace its existing Reliability Facilities Charge with a new Regulated Transmission Facilities Charge that will allow NYISO to recover from load-serving entities — and pay to transmission developers — the costs associated with any regulated transmission project that is eligible for cost allocation and recovery under its Comprehensive System Planning Process.
While New York transmission owners generally supported NYISO’s filing, they asserted that some language in the proposed revisions might inadvertently modify the abandoned plant costs that a TO or developer is eligible to recover under the state’s reliability planning process.
The commission ruled that the TOs did not explain the basis for their position and, “given the lack of specificity” in their comments, there were no grounds for it to act on their concerns. The commission also said that it already made clear that it would “grant abandoned plant recovery on a case-by-case basis and that Order No. 1000 did not provide a blanket grant of abandoned plant recovery.”
RENO, Nev. — If she had her way, the principal author of the Department of Energy’s August grid study would have written its recommendations a bit differently. And she wouldn’t have attempted to use it as a pretext for price supports for struggling coal and nuclear plants, she said last week.
Alison Silverstein, an independent consultant and former adviser to FERC Chairman Pat Wood III, gave a presentation last week at a joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Board, recommending the protection of wholesale markets and not particular technologies.
She argued that coal units are not good for grid “resilience” and contested their inclusion among so-called “baseload” plants.
“Coal plants that retired recently did not operate as baseload,” she said. “Retired plants were smaller, older, had higher heat rates, and therefore were dispatched less often and ran at lower capacity factors.”
| DOE
The department’s Notice of Proposed Rulemaking to FERC would require RTOs with both energy and capacity markets to compensate generators their full operating costs if they maintain a 90-day supply of on-site fuel.
Silverstein said that most coal plants have on-site inventories of 45 to 70 days, not 90 days as sometimes cited by coal interests.
She recommended that grid planners “identify, define, productize and compensate essential reliability and resilience services to meet multi-hazard threats and scenarios.” She said that “every essential service should be compensated,” but not all should receive market-based compensation, and “some should be conditions of interconnections with value-based compensation.”
She also recommended that renewables and demand response be used for frequency response because they are better at providing those services than conventional generation, if they receive proper incentives.
While the department’s study recommended that FERC consider action similar to the NOPR, the technical portions, of which Silverstein wrote the initial draft, contained little new information or data, citing trends familiar to observers of the markets. Many stakeholders, particularly those in renewable energy, feared that the department would attempt to manipulate the data to support its recommendations. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Their fears were heightened by the involvement in the study of Travis Fisher, a former FERC economist hired by DOE in January who had written a 2015 report for the conservative Institute for Energy Research that alleged the “single greatest threat to reliable electricity in the U.S. does not come from natural disturbances or human attacks” but federal and state government policies such as renewable subsidies and mandates.
DOE’s ‘Deregulatory Push’
Fisher was also at the conference. He said DOE will soon issue a report on its “deregulatory push” following President Trump’s executive order on reducing regulations. The department is focused on technology and cybersecurity, the latter of which is “a huge issue and a top priority” for Secretary Rick Perry, he said.
He said that the industry needs to work more closely with government, and noted that discussions at the conference had focused on better computer modeling. DOE is doing a lot of work in that area, and “we actually are here to help,” he said.
The meeting also featured a panel on contracting led by Harry Singh, a vice president at Goldman Sachs and chairman of Western Systems Power Pool. What is driving many financial players in the West is “sustainability and renewables” through renewable policies in states such as California, he said.
“Two very exciting things in the West” are the Western Energy Imbalance Market (EIM) and SPP’s move to integrate Mountain West Transmission Group, Singh said. (See SPP, Mountain West Integration Work Goes Public.) Renewable power purchase agreements have expanded in SPP and Texas because of the wind resources there, he said. Singh discussed the impacts of contracting on reliability and other issues surrounding procurement in the West.
California Public Utilities President Michael Picker discussed issues in the state’s electricity planning, and said that by 2022, up to 83% of California load could be served by third-party providers as customers depart for competitive suppliers, community choice aggregators and other programs.
“Essentially, we are seeing deregulation from the bottom up,” Picker said, adding that customer disaggregation is occurring in a number of different forums, “with not necessarily a strategy in mind.” He added that he that “we will have a variety of challenges and “these are things that everybody is going to have to deal with as they see their load disaggregate.”
LITTLE ROCK, Ark. — SPP stakeholders narrowly rejected a Tariff change last week that would have established a 1-MW threshold for reporting behind-the-meter network load, despite having directed a working group to settle the policy debate over the resources’ inclusions and exclusions.
The debate goes on.
“We’ve been working on this for three, four years,” said Southwestern Public Service’s Bill Grant during the Markets and Operations Policy Committee meeting Oct. 17. “If we can’t reach consensus, we should take it to FERC.”
At issue is how members report — or don’t report — the network load, and who has jurisdiction over that reporting.
The Regional Tariff Working Group (RTWG) attempted to settle that issue with a revision request (RTWG-RR241) that expanded the Tariff to govern the inclusion of generation on the load side of a discrete delivery point.
The revision would include in a retail customer’s network load calculation any BTM output at a discrete delivery point and in front of the customer’s meter. The calculation would also include any BTM generator — or combination of generating units — with a nameplate rating greater than 1 MW.
The revision would exclude BTM generation that is used for emergency backup operations and is not synchronized to run in parallel with the grid.
“The way we talked about this years ago, the megawatt exemption would be used and useful behind discrete delivery points, not behind the meter,” said Golden Spread Electric Cooperative’s Mike Wise. “Those of us in the hinterlands end up subsidizing [other entities’ transmission bills] because we don’t have any huge loads. If you’re going to use that [exemption], use the nodal pricing point. It’s really important to have the number of generators out there aggregated up, so you’re not going beyond 1 MW. We believe FERC will see it that way too.”
“If that generation is wholly consumed behind the retail meter, it should not be counted as network load,” said Oklahoma Gas & Electric’s Greg McAuley. “There’s enough diversity in this system where a 1-MW generator or larger somewhere is not going to make that much of a difference. We do not want FERC regulating activity behind the retail meter, period.
“We decided the FERC precedent was pretty clear, that all generation behind a discrete delivery point should be included, but not behind retail meters unless a resource behind that meter is conducting wholesale transactions,” McAuley continued. “We came down on the side that no exclusion [behind wholesale meters] is appropriate, but then this 1-MW behind the retail meter came up.”
OG&E takes the approach that it only reports the generation it owns. The company’s RTO policy director, Jake Langthorn, said the company files an annual report of every megawatt it sells.
“If it’s behind the retail meter, and generated and consumed there, OG&E doesn’t own it,” Langthorn said. “We don’t own it, we’re not going to report it.”
“We’ve been reporting that behind-the-meter generation since Day 1. If I’m reporting the load and you’re not, then that’s a problem for me,” Grant said, offering a different perspective. “You’ve got everyone at the table saying they’re reporting BTMG differently. You can tell this is an issue. I don’t know where to go from here except file a 206 complaint, and that’s a shame.”
The measure failed on a roll call vote, receiving only 54.6% of the votes in favor. When the MOPC in July directed the RTWG to address “inconsistency and uncertainty” over which BTM generation qualifies as network load, it did so by a margin of 0.2%. (See “MOPC Suggests 1-MW Threshold for Network Load,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
OG&E’s David Kays, the RTWG’s chair, shut down a suggestion that RR241 be tabled until the next MOPC meeting. He noted that this was the third time the working group has prepared a revision request, SPP has given its legal opinion, the MOPC has provided direction and the RTWG has codified the language.
“The thing [we’ve] struggled with is that every time we showed up [for a meeting], someone had a different carveout,” he said. “You open it up to a comment period, you’re right back here. I don’t know what 90 days solves.”
After the MOPC meeting, Kays sent an email to MOPC Chair Paul Malone and SPP COO Carl Monroe, the staff secretary, to request a task force be formed to take the next stab at developing a policy that ensures consistency.
Monroe later told the Strategic Planning Committee that staff would draft and share its view of how the issue should be developed.
Stakeholders Try Again with Resource Adequacy Changes
In the wake of FERC’s second rejection of SPP’s proposed resource adequacy requirement (ER17-1098), the working group responsible for the Tariff change will begin the process of drafting a new revision request to address the commission’s denial. (See FERC Again Rejects SPP’s Resource Adequacy Revisions.)
In the meantime, it will be business as usual for the SPP market, according to Municipal Energy Agency of Nebraska’s Brad Hans, chair of the Supply Adequacy Working Group (SAWG). The 10.7% capacity margin, which is equivalent to a 12% planning reserve margin, will remain in effect along with other criteria, and SPP will continue to follow the reporting timeline of the proposed change.
The SAWG plans to bring a new revision request to the RTO’s January leadership meetings. It hopes to make another FERC filing in February.
“It will be a whole new filing,” Monroe said. “We’re trying to work with FERC in order to get these things forward in a way that we will get an approved filing. If we go outside that, we run the risk of getting rejected again.”
FERC said SPP’s proposal was “inadequate,” failed to include a requirement that all power purchase agreements be backed by verifiable capacity to meet the RTO’s resource adequacy requirement (RAR), and omitted provisions to allow the RTO to verify the agreements are backed by capacity.
The commission called SPP’s proposed treatment of firm power purchases and sales in its determination of net peak demand unduly discriminatory, and that it had not supported its proposal to publicly post a list of all load-responsible entities that have not met their RAR.
“The issue is: How do you enforce the [RAR’s] criteria: through a contract enforcement or through a penalty?” said SPP General Counsel Paul Suskie. “The question is how do you enforce it, and that’s at FERC.”
A task force spent more than two years developing the resource adequacy package, which is projected to reduce SPP’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. The board and stakeholders approved the package in January. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
SPP’s Kelley ‘Undeterred’ by Missouri Projects’ Rejection
Saying he was “undeterred” by FERC’s rejection of a pair of joint projects (ER17-2256, ER17-2257), SPP Director of Interregional Relations David Kelley said he will take another shot at developing an acceptable regional allocation of the projects’ costs.
FERC said SPP’s proposal for regionwide/load-ratio share funding for its portion of two projects with Associated Electric Cooperative Inc. (AECI) and City Utilities of Springfield, Mo., had not shown they were “roughly commensurate with the projects’ benefits.” (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)
The proposed projects would add a new 345/161-kV transformer at AECI’s Morgan Substation and uprate an existing 161-kV Morgan-to-Brookline transmission line, while also installing a new 345-kV 50-MVAR reactor at City Utilities’ existing Brookline substation. SPP would be responsible for $17.1 million of the projects’ estimated $17.1 million to $18.75 million cost, as the benefits would accrue to the RTO.
“We’ve identified a good project that needs to be constructed. They’re the right projects,” Kelley said. “My goal is to try and bring back another plan of action you guys can consider at the January meeting.”
FERC’s order does not preclude SPP from making additional filings supporting regional funding or proposing a new cost allocation for the projects. Kelley said he will continue conversations with AECI, City Utilities and RTO stakeholders in order to better justify regionwide cost allocation or develop another cost allocation proposal for the projects.
“It’s really a cost allocation issue” on SPP’s side,” Kelley said.
During a separate discussion on proposed adjustments to the 2018 Integrated Transmission Planning Near-Term (ITPNT) assessment, City Utilities’ Jeff Knottek recommended adjusting the scope of the assessment to include the Brookline remedy as a “persistent operational need,” and identify the appropriate solution within the ITPNT portfolio. The motion passed with four abstentions.
The Transmission Working Group in September agreed to rebuild the assessment’s planning models, which will extend the 2018 ITPNT’s completion from April to July 2018.
Separately, the MOPC accepted the Seams Steering Committee’s recommendation of an interregional project with MISO, although the project has since been turned down by the RTO. (See SPP Glum as MISO Axes Last Interregional Project.)
“It takes two to dance, and we don’t have a dance partner,” said American Electric Power’s Jim Jacoby, the SSC Chair. “Without MISO, it’s a dead project.”
Z2 Resettlements Add $6.2M in Net Credits
Staff’s resettlement of Z2 credits for sponsored transmission upgrades has resulted in an additional $5.1 million in total net credits receivable for the March 2008-August 2016 historical period, a 2.5% increase from $203.4 million to $208.5 million.
The September 2016-August 2017 resettlement period resulted in a 1.7% increase, from $64 million to $65.1 million.
The resettlements were necessary because of billing disputes, “minor” software defects and problems in calculating the present value of creditable balances, staff told members in July. (See “More Z2 Woes; SPP to Resettle 9 Years of Data,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
Members will only be charged or credited the difference between the resettlements and the initial settlement of the Z2 crediting process.
Individual company results were posted on Oct. 13. Staff said 16 quarterly installments remain on payment plans, with the next invoices going out Nov. 3. Those invoices will include the resettlement net amounts.
Registered Entities Transitioning from SPP RE
SPP Regional Entity President Ron Ciesiel reminded members that applications to join new REs are due at NERC by Oct. 31. As of Oct. 17, he said, the commission had received only 40 applications.
The SPP RE announced its dissolution in July, addressing FERC and NERC concerns over its reliability oversight role. (See SPP to Dissolve Regional Entity.)
That move forced the SPP RE’s 120 registered entities to transition to others, a process NERC is managing. Entities should pick a new RE by Dec. 31, 2018, though Ciesiel hopes to complete the process next summer.
“Every entity should have been contacted by NERC multiple times,” Ciesiel told members.
He reminded members that the SPP RE is still the compliance and enforcement authority for its registered entities. “We’re in business as usual,” he said.
SPP has joined ReliabilityFirst but will also have to register in other REs where it does business.
Generator-Interconnection Task Force Extended for 1 Year
Members approved the Generator Interconnection Improvement Task Force’s (GIITF) request to spend an additional year developing a three-stage study process that would replace SPP’s current process built around feasibility studies, preliminary and then definitive interconnection system impact studies, and facility studies with multiple entry points.
The group is proposing stages devoted to thermal and voltage analysis, stability analysis and a facilities study. The task force’s chair, Sunflower Electric’s Al Tamimi, said the simplified process would be easier for SPP to administer and simpler for customers to understand and navigate.
Tamimi said by tying financial security to upgrade cost allocation, the proposal would encourage customers to weigh the risks of proceeding at an earlier stage and reduce the number of interconnection requests being withdrawn late in the process.
The GIITF also requested a stakeholder group with “appropriate background and expertise” be tasked with re-evaluating the purpose, scope and study requirements of network resource interconnection service to align it more closely with SPP’s current and future market structure. MOPC Chair Malone said he would work with staff to put together a task force.
The MOPC also approved the group’s recommendation to publish study models earlier in the process and eliminate the “standalone” analysis to reduce study costs and improve timeliness. SPP’s Tariff requires each interconnection request be evaluated as if it is the only request in the queue, although binding results are based on cluster evaluations.
The MOPC said goodbye to two veteran representatives: Vice Chair Todd Fridley, who is retiring from Transource Energy but will begin a new career with Public Service Company of New Mexico, and OG&E’s Langthorn, who is retiring at the end of the year.
“I remember when [SPP CEO] Nick Brown was a staff engineer,” Fridley said in thanking the committee and SPP for their support. “That’s how far back I go.”
Langthorn said that while he is ready for retirement, he has always enjoyed his work.
“This is the middle of the country. This is the heart of the country,” he said, referring to SPP’s flyover country footprint. “We really make a difference for people.”
MOPC Clears 8 Revision Requests
The MOPC approved a measure targeting potential gaming related to the regulation deployment adjustment settlements charge type. The revision (MWG-RR243) minimizes credits and maximizes charges related to the charge type, using the lesser of the as-dispatched energy offer curve and mitigated energy offer curve for the regulation-up adjustment, and the greater of the as-dispatched offer curve and mitigated energy offer curve for the regulation-down adjustment.
Keith Collins, executive director of SPP’s Market Monitoring Unit, recommended the change, saying manipulation of regulation-down offers has cost the market more than $1 million in recent years. He said that combined with MWG-RR242, which was on the consent agenda, the change addresses the MMU’s gaming concerns.
The MOPC passed two other Market Working Group revision requests, with a total of five abstentions:
MWG-RR231: Removes locally committed resources from the economic mitigation tests and creates a 10% cap for resources committed for local reliability. Addresses the practice among some resources of “self-mitigating” to pass the conduct threshold test and avoid possible mitigation with by submitting competitive energy offers 10% above the mitigated offer.
MWG-RR239: Allows market participants to incorporate fuel cost uncertainty into their mitigated offers, recovering the difference between forecasted and actual costs.
Members also unanimously approved five RRs on its consent agenda:
MWG-RR235: Corrects RR200, which removed bilateral settlement schedules (BSSs) at hubs and generation settlement locations from the over-collected losses (OCL) distribution calculation. The RR modifies two equations in RR200 to accurately reflect its true intent.
MWG-RR236: Changes the commercial model implementation from a bimonthly process to monthly. Previously implemented on only even-numbered months (February, April, etc.), the process hindered market participants with contracts becoming effective at the beginning of the year from submitting model updates on the remaining odd-numbered months.
MWG-RR242: Adds a fourth criterion, based on a resource’s cleared energy offer, for prioritizing the order in which they are deployed for regulation-up and regulation-down and addressing a potential gaming opportunity. The higher the offer, the less likely a resource will be deployed for regulation-up, and the lower the offer, the less likely it will be deployed for regulation-down.
RTWG-RR238: Addresses the financial exposure to SPP and its market participants stemming from a defaulting transmission customer avoiding responsibility for the full amount owed for the full term of a service agreement. The change also restricts the ability of SPP, transmission owners and transmission customers from recovering attorney’s fees related to performance of a service agreement, and clarifies that each party to an arbitration under the Tariff is responsible for its own fees.
RTWG-RR244: Eliminates credits from new upgrades that do not add transfer capability under Tariff Attachment Z2, and eliminates credits from short-term service under the same attachment, as recommended by the Z2 Task Force. (See “Z2, Two Other Task Forces Expire,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)
