WILMINGTON, Del. — PJM and its Independent Market Monitor remain at odds over whether price-based offer updates should be connected to cost-based offers and specified in each unit’s fuel-cost policy.
At last week’s Markets and Reliability Committee meeting, PJM’s Lisa Morelli outlined the RTO’s planned Manual 11 revisions for implementing intraday offers. The presentation was the culmination of a long debate at August’s Market Implementation Committee meeting, where stakeholders pressed PJM and the Monitor to find as much common ground on the issue as possible. (See “Stakeholders Push PJM and IMM for Consensus on Intraday Offers Rules,” PJM Market Implementation Committee Briefs: Aug. 9, 2017.)
Morelli’s presentation outlined where PJM and the Monitor continue to differ on linking a unit’s price-based offer to its fuel-cost policy. The RTO believes there’s no need for them to be linked, but the Monitor says updating price-based offers should be limited to simultaneously updating cost-based offers, which must be specified in the unit’s fuel-cost policy.
“We think it’s the only way to ensure that the timing of price-based offers and cost-based offers don’t permit the exercise of market power,” Monitor Joe Bowring said. “What we’re concerned about is this will result in one-way optionality for the generators to raise prices during the day but not be required to reduce costs when gas costs go down.”
The two sides will continue to seek compromise until the September MRC meeting, but they will have to pursue separate Tariff revision proposals if they haven’t reached agreement by then, Morelli explained. It could come as a new problem statement for stakeholders to consider, she said.
On energy-offer verification, PJM and the Monitor also remain divided over whether self-certification by the curtailment service provider is sufficient validation for demand response. The Monitor says it is not.
“The main arbiter in this is really FERC,” PJM’s Rami Dirani said. “So FERC has to really decide whether this approach is actually the proper approach going forward.”
There is also some difference of opinion on the exception process for verifying offers that are not consistent with a unit’s fuel-cost policy, verifying offers over 1,000/MWh and verifying operating reserve credits for verified offers over $1,000/MWh, but PJM believes the two sides are moving toward a compromise.
Summer-only DR to be Studied
Stakeholders approved by acclamation a problem statement and issue charge regarding summer-only DR, but not before state and consumer representatives pushed for additional revisions.
The proposal came out of the Seasonal Capacity Resources Senior Task Force, which culminated in a seasonal resource aggregation filing and approval at FERC late last year, PJM’s Scott Baker explained. However, RTO staff pared the problem statement’s scope down to eliminate other seasonal resources, such as wind, hydro or energy efficiency.
John Farber with the Delaware Public Service Commission asked for a friendly amendment that specifically noted analyzing the load forecast would be in the scope of the group.
“One of the values of DR is to manage the peak. A managed peak costs less than one that’s not managed,” he said.
Greg Carmean, executive director of the Organization of PJM States Inc., noted the Energy Policy Act of 2005 stipulated that unnecessary barriers to DR participation in the markets be removed. “I haven’t seen where PJM has gone back and evaluated whether or not their annual product actually is a barrier to demand response,” he said.
Stu Bresler, PJM’s senior vice president of operations and markets, said that the RTO’s strategy paper on DR indicates how it intends to move forward on the issue. The problem statement identifies several items that are already considered out of scope, including loss-of-load expectation analysis; seasonal capacity procurement or developing a seasonal market; re-establishing non-Capacity Performance products such as base capacity; or limited DR.
The initiative is following through on the strategy paper’s list of goals. PJM’s Pete Langbein said the Demand Response Subcommittee will be working on those in sequential order.
“I think this problem statement is a continuation on working on valuing DR,” Baker said.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said recent PJM rule changes have “hit hardest” on residential DR viability, “so this is great to see PJM taking these efforts.”
“The current construct is a barrier for residents to participate,” he said. He asked that PJM reconsider DR’s potential as a capacity product, but Baker declined to include the amendment.
PJM’s Ken Seiler provided some initial observations on PJM’s response to the Aug. 21 solar eclipse, saying the analysis will be used to better prepare for the 2024 eclipse, whose path of totality is expected to cross over PJM’s western edge.
Operationally, he said the RTO performed without incident. “We had enough regulation; we had enough reserves.”
About 2,200 MW of solar generation was lost, he said, but that remains largely an estimate as about three-quarters of it is behind-the-meter generation. Only about 500 MW was grid-connected and directly observable.
“The real surprise” came when operators saw CAISO and MISO curtailing units in expectation of lower demand, he said.
“We thought the load would be pretty much flat,” but PJM also saw a load drop similar to other grid operators, Seiler said. PJM had a load of about 133,600 MW about 1:45 p.m., which dropped to 129,500 MW an hour later.
| PJM
Weather likely accounted for some of the decline. Certain regions saw temperatures drop by up to 10 degrees Fahrenheit, which “does seem to correspond fairly significantly with the load drop,” he said. The weather forecast predicted temperatures in the 90s, but the average was around 85, he said. Additionally, unpredictable “pop-up” storms materialized in the footprint, which have a dampening effect on temperature.
“Certainly, wind and weather and cloud cover provided some level of impact,” he said.
However, human activity seemed to also play a major role. PJM found through discussions with the Nest home thermostat supplier that the company had advised customers that they could cut back on air conditioning during the eclipse to compensate for the reduction in solar output, resulting in a 750-MW drop in load.
Additionally, people departing from their normal business day to view the eclipse caused a reduction. PJM received reports that some manufacturing facilities delayed lunch and instead shut down during the eclipse.
Stakeholders Approve Misc. Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 11: Energy & Ancillary Services. Revisions, along with others associated with the Regional Transmission and Energy Scheduling Practices document, were developed as part of the implementation of Coordinated Transaction Scheduling, a new real-time energy scheduling product across the PJM-MISO interface.
Tariff and Operating Agreement revisions that clarify the two-year limit on requests for billing adjustments.
Joint operating agreement and Tariff revisions to develop a pro forma agreement for dynamic scheduling. (See “OC Discusses Pro Forma Agreements for Pseudo-Ties, Dynamic Schedules,” PJM OC Briefs: July 11, 2017.)
VALLEY FORGE, Pa. — As PJM begins to define its overarching principles for assessing cost-containment guarantees in competitive bids for developing transmission projects, one is destined to remain contentious.
“A cost-cap commitment is only one factor considered by PJM in its overall review and evaluation of project proposals for selection in the [Regional Transmission Expansion Plan],” the RTO has said.
Some merchant transmission developers, such as LS Power, are pushing to have those commitments become a defining factor, while PJM transmission owners, such as ITC Holdings and Public Service Electric and Gas, have argued that other aspects should be given just as much weight. State and consumer representatives have also expressed support for giving increased weight to cost caps. (See Containment Policy: PJM Takes Up Cost Caps.)
Beyond being one of many factors considered in a project proposal, cost-cap provisions would be voluntary and limited to project construction costs. PJM’s Craig Glazer outlined the RTO’s other proposed principles last week at a special session of the Planning Committee on the topic. They include:
Clearly articulating the cost-cap commitment in the proposal submission, along with what is covered and any exclusions;
Providing proposed contractual language on covered and excluded items;
Ensuring that all cost-cap terms and conditions will be made public, while any information and part of the proposal inappropriately labeled as confidential will not be considered;
Supporting the rationale for any exclusions, with PJM evaluating the risk and potential cost impact of excluded events;
Providing quarterly progress updates, with cost-cap enforcement through FERC’s ratemaking process; and
Reserving for PJM’s Board of Managers the right to reconsider projects that aren’t making required progress and reassign completion to another developer.
“If the cost cap gets exceeded, I don’t want [PJM] to be the only entity that sues to enforce the DEA [designated entity agreement],” Glazer said. “The cost cap portion of the DEA … is really an agreement with FERC, an agreement with the ratepayers: Here’s what the project is going to cost.”
He explained that the legal process would likely require action from the developer to address the overages.
“The shoe would be on the developer’s foot to try to recover those costs,” he said. “PJM would provide an opinion on that subject, but we’re not central to that case. You’re not suing PJM for having violated the DEA.”
LS Power’s Sharon Segner said PJM was missing as an overarching principle that meaningful cost caps are preferable to cost estimates. When RTO staff hesitated to agree to that, she argued that additional clarity is needed in how proposals are being evaluated.
“If you go back to the original language in Order 1000 … there was specific instruction to the regions to disclose how proposals will be evaluated,” Segner said. “I think it’s reasonable to the development community for PJM to give general guidance on how it uses cost estimates versus cost caps in the evaluation process, and I think that is consistent with the mandate of Order 1000.”
“To simply make a bland statement that we value cost caps — and we do — it has no value,” PJM’s Steve Herling said. “The problem is the cost cap has 100 different parts, and depending upon how you structure those parts, you have a cost cap that’s valuable or a cost cap that’s completely meaningless. So for us to make a general statement that we value cost caps, it’s motherhood and apple pie, but it doesn’t actually tell you anything.”
“All I’ve heard so far was ‘meaningful cost caps’ or ‘valuable.’ … Propose [legal] language because we’re kind of at a loss as to what would be good here,” Glazer said.
“We’re comfortable with the fact that you’re considering cost caps,” ITC’s Brenda Prokop said. “We’re not comfortable with it being always the most important factor. We don’t think that’s appropriate.”
PSE&G’s Alex Stern agreed with that.
John Farber of the Delaware Public Service Commission urged patience in making any definitive decisions on the issue.
“Cost caps are a recent phenomenon, and it’s way too early in my opinion for PJM to be forced to make definitive statement as to the role cost-cap proposals would have in its evaluation,” Farber said. “I tend to agree with Sharon that legally binding cost caps could be superior to just cost estimates or desktop worksheets — but that doesn’t mean that they would be. I think PJM needs to gain experience with cost-cap proposals to understand how different terms have different effects.”
Glazer explained that part of PJM’s hesitation is how a proposal with a cost cap should be considered if it is substantially higher than a credible proposal with just a cost estimate. He described the cost cap in that situation as a “fig leaf” designed to attract positive consideration.
But Greg Poulos, the executive director of the Consumer Advocates of the PJM States, argued that giving caps deference doesn’t mean they have to be determinative in every situation. “I think there’s a big difference between the two,” he said.
The group has its next meeting scheduled for Sept. 8.
VALLEY FORGE, Pa. — With nine proposals to compare and four months left in the year, stakeholders appear to be eyeing the finish line of PJM’s yearlong effort to consider reforming its capacity construct.
Last August, a coalition of public power organizations, concerned that conversations about potential modifications to the RTO’s Reliability Pricing Model regarding the impact of state policies were taking place out of the PJM stakeholder process, began a campaign to win stakeholder approval to re-examine the RPM.
The Capacity Construct/Public Policy Senior Task Force (CCPPSTF) started meeting in March with a goal of filing with FERC by the end of the year any changes to the capacity market stakeholders agree to make.
That ambitious timeline has led the CCPPSTF to meet about twice a month and schedule six meetings in August alone. At the group’s fifth meeting for the month, stakeholders began to show signs of restlessness.
The Skinny Model
PJM’s Murty Bhavaraju explained additions to a model developed by RTO staff to compare nine capacity revision proposals using fictional and simplified numbers. PJM’s Dave Anders called it a “skinny model” because it’s designed to be shaved down to just the essential pieces to understand the mechanics of the proposals.
Adrien Ford of Old Dominion Electric Cooperative pressed RTO staff to make the model more representative of real-world conditions so that stakeholders can determine whether any of the nine proposals would work better than the existing process.
“I’m just hopeful that this skinny model is Step 1 in the analysis,” she said. “This doesn’t get me to the point where I understand whether we have an issue. … People are going to look at the numbers and the numbers aren’t realistic.”
PJM has resisted using historical numbers in the models because they will require incorporating a lot of assumptions that could drastically skew results, which stakeholders might incorrectly view as price forecasts. (See PJM Stakeholders Begin Defining Capacity Design Needs.)
Greg Poulos, executive director of the Consumer Advocates of the PJM States, asked staff to develop some way to whittle down the options to compare.
“There’s still so many on the table, it makes it hard to think about where we’d go,” he said.
Panoply of Proposals
Another round of proposals received updates from their initial presentations based on feedback.
American Municipal Power filled in some blanks in its proposal, which would emphasize long-term bilateral contracts and reduce the significance of the forward-looking annual capacity auction to fill in whatever capacity obligations remain outstanding beyond the contracts.
AMP’s Steve Lieberman said the auction would be held between 12 and 18 months prior to the start of the delivery year, with a single Incremental Auction held 30 to 60 days ahead of the delivery year. Under the current construct, PJM holds Base Residual Auctions three years ahead of the delivery year, with IAs occurring annually after that until the delivery year.
AMP is also developing the idea of a secondary capacity exchange.
John Hyatt with Monitoring Analytics expanded on the Independent Market Monitor’s proposal to extend the existing minimum offer price rule (MOPR). Monitor Joe Bowring has long argued that competitive, pure markets are unable to accommodate subsidized bids; therefore such bids must not be allowed to influence auction results.
Jennifer Chen with the Natural Resource Defense Council provided additional context to the Sustainable FERC Project’s proposal, which would reduce the capacity requirement to the needs of the off-peak season and allow seasonal resources to account for the additional demand during the peak season.
Chen said her plan would use the BRA construct to procure always-ready Capacity Performance resources up to the needs of the off-peak season (i.e., winter needs for summer-peaking zones and vice versa), then allow the peak season to be addressed using what she termed a “seasonal CP product.” The plan would shift the variable resource requirement demand curve left, reducing the annual procurement to account for the reduced amount of CP resources procured.
The plan has no repricing mechanism to eliminate the influence of subsidized offers. Subsidies that only compensate for a desired attribute, such as carbon-free generation, would leave the generation unit free to offer into the BRA to be compensated for its contribution to resource adequacy. Units that receive a subsidy sufficient for full compensation would be treated like a contracted resource, and the load-serving entities contracting that source could opt out of a corresponding amount of its capacity obligation.
The proposal left stakeholders perplexed.
“I don’t get how it addresses [subsidized units’] impacts on the market,” said Carl Johnson, who represents the PJM Public Power Coalition. “I’m really confused about how mechanically this would do that.”
Chen said her reading of the task force’s charter was that the goal is to accommodate state actions to promote certain fuel types and that her proposal does that.
Johnson asked for Chen’s proposal to outline what it definitively commits to, but Lieberman defended the ability of the proposals to be flexible.
“To me that’s actually a positive that some of these proposals don’t seem so stuck to where they’re at” and are open to feedback and revisions, he said.
The task force is turning its focus to identifying appropriate polling questions and potential repricing triggers, but both efforts received stakeholder criticism.
ODEC’s Ford asked why staff wanted to develop polling questions rather than just determine the popularity of the nine proposals. PJM’s Anders, who is facilitating the group, said he believes the group’s final vote should be on the package’s relative popularity.
“I hear your point that it may not be ready to poll on the packages,” Ford said. A poll on various capacity construct components is “better than nothing,” she said, “but it would be better to poll the packages.”
Exelon’s Jason Barker asked why the task force was waiting to address the repricing triggers, as most proposals reference a trigger but fail to identify a specific mechanism. Anders said that since almost all of them are to be determined, the actual trigger can be determined later once the group has agreed on a plan.
Great Plains Energy has pulled back from its attempted acquisition of Westar Energy, recasting the move as a “merger of equals” after the two companies last week asked Kansas regulators for permission to merge under a tax-free share exchange.
The Kansas Corporation Commission blocked an earlier version of the deal in April, criticizing the $60/share purchase price as too high. (See Westar Shares Fall as Kansas Regulators Block Great Plains Deal.) Shareholders are poised to gain less in the new, stock-for-stock proposal.
| Great Plains and Westar
Under the new proposal, Great Plains would no longer become Westar’s parent company. Instead, the two companies would combine under a $14 billion holding company operating in Kansas and Missouri. Westar shareholders would own about 52.5% of the company with Great Plains shareholders holding the rest, according to the amended merger application (18-KCPE-095-MER).
The new deal would entail no cash exchange or transaction debt, and retail customers would receive $50 million in upfront bill credits across all rate jurisdictions. The combined company would serve about 1 million customers in Kansas and almost 600,000 customers in Missouri.
The two companies are expected to retain their original names after the merger, and Westar will continue to maintain an operating headquarters in Topeka, Kan., staffed by 500 employees. The companies have pledged not to lay off any employees. Corporate headquarters for the merged company would be located in Great Plains’ Kansas City, Mo., location.
The plan requires approval from both the KCC and the Missouri Public Service Commission. The companies will also file applications before FERC and the Nuclear Regulatory Commission as early as this week and will seek respective shareholder approval during the fourth quarter. If approved, the deal is expected to close in the first half of 2018.
The CEOs of both companies say the revised agreement represents savings for customers and an opportunity for long-term growth for shareholders, while better positioning the companies to invest in infrastructure.
“We carefully listened to the KCC’s concerns with our original transaction and crafted a new merger agreement using the KCC’s earlier order for guidance to bring better value to customers and shareholders of both utilities compared with remaining standalone,” said Great Plains CEO Terry Bassham.
Westar CEO Mark Ruelle called the merger “a long and unpredictable path” during a second-quarter earnings call in early August: “We spent a lot of time in May and June confirming that there wasn’t just a stop sign in the order, but also road map to approval. … It wasn’t the course on which we first set out, but I’m pleased where it’s taken us and encouraged by the value it creates for our customers and our shareholders. The KCC order was clear that a big premium deal was going to be problematic.”
Fewer Future Rate Cases
In testimony to support the filing, Ruelle said that without a merger, Westar’s “flat sales and rising costs” will translate into higher prices. Bassham testified along similar lines, saying that “costs to serve … customers will continue to rise unchecked” and absent a merger, Great Plains “would need to seek higher prices and more frequent price increases as the remedy for any unmitigated higher costs.”
Both CEOs claim the merger will lessen the need for future rate cases.
“With the merger savings, we’ll no longer be as dependent on rate cases to produce earnings,” Ruelle said during the earnings call.
In early August, Great Plains posted a second-quarter loss of $22.1 million ($0.10/share), while Westar announced earnings of $72 million ($0.50/share), in line with last year’s second-quarter results.
AUSTIN, Texas — With Hurricane Harvey rapidly gaining strength in the Gulf of Mexico and threatening the Lone Star State, ERCOT’s Technical Advisory Committee on Thursday focused on three tabled revision requests and appeals before quickly scattering to their homes and work.
“Be safe,” urged TAC Co-Chair Bob Helton, of Dynegy, as he adjourned the meeting.
Committee members did approve one of the three tabled issues, passing a nodal protocol revision request (NPRR768) after staff filed comments most could agree to. The NPRR was the subject of vigorous debate during the July TAC meeting but was passed this time with only Shell Energy and Sharyland Utilities abstaining. (See “EEA Price Adder Change Tabled,” ERCOT Technical Advisory Committee Briefs: July 27, 2017.)
The revision request adds real-time DC tie imports and exports through registered block load transfers to the list of ERCOT-initiated actions that trigger a price adder to ensure that prices reflect scarcity conditions.
Staff revised the language to cap the total adjustment for DC tie imports at 1,250 MW, the current capacity of all DC ties.
That was enough to placate the Texas Industrial Energy Consumers group, which has opposed the measure throughout the stakeholder process.
“We have a philosophical disagreement about whether this is appropriate,” said Katie Coleman, legal counsel for TIEC. “Rather than continue fighting about that, we got comfortable about moving this forward with a megawatt limit on it.”
Shell’s Greg Thurnher called the revised language a “nice compromise” and a “step in the right direction” to support scarcity pricing signals, but said he wasn’t sure “every adder is a good adder.”
“This one has a lot of fine print,” Thurnher said. “We’ve had some growth in traditional [DC ] ties that could be excluded for the circumstances it’s trying to prevent. We’ve arrived at the solution, but I’m not sure it’s a good one.”
NPRR768 does not address the Southern Cross Project, a proposed HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeastern markets. Several stakeholders agreed that is a discussion for a later date.
“When we wrote this, we tried to recognize what exists today,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “We don’t believe it’s biased toward anything. Our process allows the accommodation of whatever the future is going to be. This was our effort to put something forward to get to a compromise and recognize some of the concerns.”
Shell filed comments to ERCOT’s revisions, suggesting modifying the NPRR to restrict price correction to imports ordered on DC ties classified as transmission facilities. Cratylus Advisors’ Mark Bruce, speaking for Southern Cross, disagreed with the change.
“It seems pretty clear to us that once the Southern Cross project is interconnected to the ERCOT network, it will be a transmission element by definition, which means the definition of a transmission facility has to be amended to include it,” Bruce said. “Shell’s comments don’t really change anything. It actually opens it up and includes Southern Cross when it goes live.
“The ERCOT approach, on its face, is sort of less discriminatory. It doesn’t really start distinguishing between transmission facilities based on regulatory classification or ownership structure of the facility, which in our view isn’t a permissible way to go about this. In our view, this is either a good policy, [and] you put the megawatts in the calculation, or it’s not good policy, and you don’t.”
“Our intent was to impose a limit,” Thurnher responded. “The protocols get tricky when they define things. I think of Southern Cross as a load sometimes and a generator sometimes, neither of which are transmission assets. If Southern Cross gets built, then this needs to be revisited.”
Said Coleman, “We are intentionally leaving that for future discussion.”
CRR Deration Remanded Back to Subcommittee
The TAC unanimously remanded back to the Protocol Revision Subcommittee NPRR821, which failed to pass the committee in July after substantial discussion, to reconcile “three very different” modifications proposed by stakeholders.
The revision request would eliminate the reduction of congestion revenue rights (CRR) payments, or deration, by reversing the day-ahead market’s deration-settlement mechanism. The mechanism, which was introduced to deter market manipulation, has resulted in large financial losses to generators.
The deration price for a CRR path is determined at the constraint level and applied to the CRR payout. Payments can be derated if transmission elements are oversold, the target payment is a positive value, or the CRR source or sink is a resource node.
The Lower Colorado River Authority filed two proposed adjustments to NPRR821 following a $1.9 million loss in 2016 that it called “unusual and unique.” LCRA said it worked with ERCOT and others in attempting to find a balance between low impact and low implementation cost.
The company’s preferred solution was linking the CRR’s holder and the point-to-point (PTP) obligation of the qualified scheduling entity on the same path. It suggested linking the PTP price to the corresponding CRR value if a PTP obligation bid is awarded to a QSE with a CRR. If the CRR is derated, the PTP bid’s settlement price is matched to the CRR’s derated value.
The second option would cap the PTP’s value at the derated CRR’s value on the same path.
“It’s clear a lot of folks still have a learning curve with how this process works and the way the money flows,” said LCRA’s Randa Stephenson. “If it’s TAC’s will to send this back, please be ready to vote on this. This is going to be an issue that comes back to us.”
ERCOT staff agreed and volunteered to put together a presentation detailing all the proposed modifications.
“I just want to make sure everything’s clear,” Ögelman said, noting that LCRA’s proposal considers PTPs, not CRRs. “People need to look at all of these things to understand all of the mechanisms.”
DC Energy’s suggestion to add a “circuit-breaker” lowering the capacity offered in the CRR monthly auctions when the balancing account reaches zero at the end of any month drew positive feedback from several stakeholders.
“It’s a little bit more protection for our customers,” said Austin Energy’s Barksdale English.
Under DC Energy’s proposal, the CRR balancing account would be allowed to rebuild its value before reverting to the 90% capacity offering status quo.
Morgan Stanley offered the third proposal, which it said would “level the playing field” for all CRR participants by making short pays equivalent, regardless of the source or sink of the owned CRRs. Eliminating the current process — which covers hub and load zone CRRs and provides hedge value for those instruments involving resource nodes (well over half of these shortfalls) — would eliminate the expense created for load, the company said.
“There was a request to try and narrow the NPRR, and this narrows the application as far as you can get it,” said Morgan Stanley’s Clayton Greer, whose first preference was either the original NPRR or DC Energy’s proposal. “It actually eliminates all short-pay recoveries and hedge payments entirely. The retail segment argued that derate support was being done on the backs of load. If that’s the case, then all derate coverage would be on the backs of load.”
The Protocol Revision Subcommittee (PRS) plans to return with new language for NPRR821 in September.
Small Municipalities’ Appeal Tabled Again
The committee once again tabled the Small Public Power Group of Texas’ (SPPG) appeal of a rejected revision to the Nodal Operating Guide (NOGRR149) regarding the definition of transmission owners. In granting a six-month extension until February, the TAC agreed to take up the “substance of the appeal” at that time.
The revision would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission operator services from a third-party provider if their annual peak load is less than 25 MW. The proposal was developed in 2015 to settle the noncompliant status of six municipally owned utilities with loads from 9 to 21 MW.
The SPPG has been filing monthly updates since the appeal was last tabled in January. In its most recent, the group said, “significant progress has been made” in reaching permanent market solutions for its members’ designated TO service, but they have not yet been achieved.
“All of these have been proceeding as hard and as fast as they can,” said Tom Anson, legal counsel for SPPG. “These things take more time than you think. We want another six months to keep working hard at it.”
The appeal has now been tabled eight times since it was first brought to the TAC in March 2016, shortly after it failed to pass the Reliability and Operations Subcommittee.
PRS Adds Resource Definition Task Force
The PRS brought forward two unopposed NPRRs and announced the formation of the Resource Definition Task Force. The task force, chaired by Vistra Energy’s David Ricketts and ERCOT’s Jay Teixeira, will work to synch up the ISO and Public Utility Commission of Texas’ definitions.
The TAC tabled NPRR829, one of two unopposed revision requests, to allow ERCOT time to refresh its initial impact statement. Staff said it believes the second impact statement, which should be complete for the next PRS meeting, will come in above the current $120,000 to $160,000 estimate to implement.
NPRR829 requires the use of telemetered data from non-modeled generation in the day-ahead market to more accurately calculate QSE collateral requirements. The change will increase day-ahead liquidity through the increased participation of non-modeled generation, and potentially allows ERCOT to gain near real-time transparency into the generation.
The committee unanimously approved NPRR836, which incorporates the following “other binding documents” into the protocols as a new Section 23 (Forms): Congestion Revenue Right Account Holder Application Form, Load Serving Entities Application Form, Managed Capacity Declaration Form, Market Participant Agency Agreement Form, Notice of Change of Information, QSE Agency Agreement Form, QSE Application Form, Qualified Scheduling Entity Acknowledgement, Resource Entity Registration Form, Transmission/Distribution Service Provider Registration Form and WAN Agreement.
Changes to these Section 23 forms will be made using the NPRR process.
The coal industry’s hopes were boosted in April when Energy Secretary Rick Perry called for a report on what he said were risks to grid reliability caused by the retirement of “baseload” coal power plants. Both coal supporters and opponents saw Perry’s April 14 memo as a means for President Trump to deliver on his promise to “save” the industry.
Trump (left) and Perry
But the study released Wednesday didn’t support several of the premises Perry laid out, nor did it provide the unambiguous case for coal that partisans on both sides expected. (See related story, Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
The report came the day after the Associated Press reported that the Trump administration had rebuffed the industry’s request to declare an emergency that would have allowed Perry to keep threatened coal plants running. (See related story, Despite Promise to Save Coal, Trump Rebuffs Emergency Call.)
In a blog post Monday, National Mining Association spokesman Luke Popovich praised the report’s recommendations on valuing on-site fuel supplies and pressed for what he called a “more forceful, vigilant role for FERC in overseeing and managing the grid” as “constructive and necessary.” He acknowledged, however, that the recommendations “weren’t revolutionary or bold.”
Popovich also praised the call for changing EPA’s New Source Review rule on coal plants, which the report said “discourages rather than encourages installation of CO2 emission control equipment and investments in efficiency.”
But because implementing such a change would likely require amending the Clean Air Act — no small task — it is unlikely to provide relief any time soon.
“Hurricane Harvey will likely have a bigger impact on the energy grid than this vanilla report,” Popovich concluded.
Much is at stake. The Department of Energy said a net 36 GW of coal capacity retired between 2002 and 2016, about 12% of total coal capacity. Coal mining company Murray Energy says 24 coal fired plants are scheduled to close over the next year.
Ensuring a Place for Coal?
The best hope for the coal industry may be that FERC could adopt the report’s recommendation that it lean on RTOs to begin valuing on-site fuel storage as a measure of “resiliency.” At least one FERC commissioner, acting Chair Neil Chatterjee, has indicated he is receptive.
In a podcast interview posted Aug. 14, Chatterjee said one of his primary goals is supporting coal, the favored fuel in his home state of Kentucky — also the home of his former boss, Senate Majority Leader Mitch McConnell.
“Baseload power … including our existing coal and nuclear fleet, need to be properly compensated to recognize the value they provide to the system,” Chatterjee said, citing their value to “resilience and reliability.”
“I’m a Kentucky native,” he continued. “I’ve seen firsthand throughout my life how important a contribution coal makes to an affordable and reliable electric system. Last year, coal provided over 80% … of the electricity in Kentucky. As a nation, we need to ensure that coal, along with gas and renewables, continue to be part of our diverse fuel mix.”
Chatterjee, the acting chairman pending the confirmation of fellow Republican Kevin McIntyre, did not elaborate on how he intended to accomplish his goal in the interview.
His comments suggest the commission could be entering a new, more contentious environment. FERC policy until now has been — in the words of former Commissioner Philip Moeller — “fuel neutral but not reliability neutral.”
“Chatterjee comes out for coal and nukes specifically. [Fellow Republican Commissioner Robert] Powelson has been a great friend and promoter of gas. [Democratic nominee Richard] Glick could be called a renewables advocate,” observed one former senior FERC official who asked not to be named. “For the first time we could have FERC fuel wars.”
FERC did not immediately return a request for comment on Chatterjee’s remarks.
“All the fingers seem to be pointing, rightfully, at FERC,” Paul Bailey, CEO of the American Coalition for Clean Coal Electricity (ACCCE), told the Washington Examiner last week. “I think most people understand the need for speed; the question is whether this whole system with FERC and the grid operators, and technical conferences, are set up to move these things quickly.” Bailey declined an interview request from RTO Insider.
“I think it’s all going to come from what time frame FERC gives these grid operators,” Michelle Bloodworth, ACCE’s chief operating officer, told the Examiner. “If they kind of say, ‘well, OK, we’ll let you talk to your stakeholders,’ then I’d say they would take years.”
Bloodworth said the group hopes FERC will act as it did following the 2014 polar vortex, when it ordered grid operators to report within 90 days on their efforts to ensure generators have adequate fuel. (See NERC Optimistic on Winter Prep as FERC Seeks Assurances on Fuel.)
Facts Don’t Support Perry Thesis
The department’s 187-page report failed to support the claim in Perry’s memo that generation diversity has declined (it is actually more diverse than ever, the report said) or that renewable power was largely to blame for coal and nuclear plants’ financial problems (renewables were identified as a secondary factor, far less important than competition from cheap natural gas).
Nor did the report provide evidence that coal plant retirements have caused threats to grid reliability. It noted that NERC’s most recent State of Reliability report concluded “bulk power system reliability remained … adequate” in 2016, repeating the group’s findings from 2013–2015.
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
Perry’s contention that “baseload power is necessary to a well-functioning electric grid” was also undermined by the study, which quoted NERC CEO Gerry Cauley as saying “resource flexibility is needed to supplement and offset the variable characteristics of solar and wind generation.”
However, Cauley also noted the need for replacing “essential reliability services, such as frequency and voltage support, [and] ramping capability,” lost with the retirement of conventional generation.
In a blog post, John Moore, director of the Natural Resources Defenses Council’s Sustainable FERC Project, and NRDC attorney Miles Farmer said the study “grasps for any possible rationale to support outdated, expensive and highly polluting coal plants, but fundamentally fails to come up with concrete reasons to do so.”
“The report is disjointed, making misguided recommendations to relax environmental rules and saddle customers with extra costs that are largely unconnected to and unsupported by the report’s findings,” they said. “In short, while we believe customers should pay less and get cleaner energy, Trump and the coal industry want customers to pay more and get dirtier energy.”
Defining ‘Resilience’
The report continues attempts by coal and nuclear supporters to identify a new attribute — resilience — in addition to traditional measures of reliability. Where reliability is reflected in loss-of-load events — commonly seeking no more than one outage day every 10 years — resiliency refers to the ability to respond to supply disruptions caused by catastrophic weather or cyberattacks.
ACCCE said before the report that it hoped the department would “explain the distinction between reliability and resilience; call for resilience analysis and the establishment of uniform resilience criteria.”
“The DOE study should identify attributes that strengthen grid resilience (e.g., on-site fuel supplies, firm fuel contracts, and black start capability) and attributes that can diminish grid resilience (e.g., just-in-time fuel delivery, fuel storage disruptions, pipeline outages, interruptible fuel contracts and over-reliance on any one fuel type.)”
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
Supporters say coal should receive compensation for having 60 to 90 days of fuel at plant sites; operators of nuclear plants, which refuel every 18 to 24 months, have made similar claims. (See related story, Nuclear Industry Seeks PPAs, FERC, RTO Action After DOE Grid Study.)
Most natural gas generators, in contrast, have little storage on site and rely on just-in-time pipeline deliveries.
ACCCE said one-quarter of the natural gas burned by generators in the nation’s largest power pools in 2016 was delivered under interruptible contracts, which allow pipelines to cancel them with little or no notice. Interruptible gas use was highest in NYISO (61%) and ISO-NE (57%), the group said.
The American Gas Association, which represents distribution utilities, insists the gas transmission and distribution system is “inherently resilient” compared to other energy delivery systems.
“Natural gas systems are far more resilient in the face of extreme weather events because natural gas pipelines are predominantly underground and more protected from the elements,” AGA President Dave McCurdy said in response to the report last week. “Our natural gas infrastructure also has the advantage of built-in redundancy of interconnections for receipt and delivery of natural gas.”
The study noted that during the 2014 polar vortex, many natural gas-fired generators with non-firm gas contracts had their fuel supplies curtailed while others were unable to operate because the cold caused fuel to gel and some pipelines to freeze. But it also notes that “many coal plants could not operate due to conveyor belts and coal piles freezing.” Nuclear generators, it said, fared best during the cold spell, recording an average capacity factor of 95%.
Fuel Diversity not a Panacea
The American Petroleum Institute released a report in June that argued it is not fuel diversity, but the presence of “reliability attributes,” that policymakers should seek for the good of the grid. The study, done for API by The Brattle Group, concluded that gas-fired generation is “relatively advantaged” in all but one of the 12 attributes it identified, failing only on storage capability. (See NG Lobby Goes on Offensive vs Coal, Nukes.)
API said the report was not intended to pre-empt the DOE study but “to push back against” state policies that seek to maintain coal and nuclear plants “at any cost.”
In March, PJM issued a study concluding it could maintain adequate reliability with a generation fleet almost entirely composed of natural gas units, but that a capacity mix of more than 20% of solar would unacceptably increase the LOLE risk. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
Nevertheless, in June, it issued a report proposing to allow nuclear and coal plants needed for reliability to set clearing prices based on their marginal costs. (See PJM Making Moves to Preserve Market Integrity.)
Despite Promise to Save Coal, Trump Rebuffs Emergency Call
On Aug. 4, coal magnate Robert Murray wrote an impassioned letter to a White House aide. Merchant generator FirstEnergy Solutions is “on the verge” of a bankruptcy filing that would force the company to immediately close its coal-fired generators, he wrote. “Their bankruptcy will force Murray Energy Corp. into immediate bankruptcy, promptly terminating our 6,500 coal mining jobs” and leaving the company unable to make $140 million in debt payments due between September and December.
In a later message, Murray said, “these bankruptcies would have a cascading effect which would decimate the states of Ohio, West Virginia and Pennsylvania, all of which voted overwhelmingly for President Trump.”
During the presidential campaign, Trump famously donned a miner’s helmet and promised to save the industry.
Nevertheless, the Associated Press reported Aug. 22, the Department of Energy rejected Murray’s plea that it use its emergency powers under the Federal Power Act to order a two-year moratorium on the closing of coal-fired generators.
The AP obtained letters in which Murray claimed Trump had promised to take the emergency action. The letters said Trump made his commitment in private conversations with executives from Murray and FES, one of the coal mining company’s biggest customers. The CEOs of mining companies Peabody Energy and Alliance Resource Partners also had called for an emergency declaration.
The White House declined to say whether Trump had promised to act, but a spokeswoman told the AP that the White House was helping the industry in other ways. “Whether through repealing the Clean Power Plan and the ‘Waters of the U.S. Rule,’ removing the U.S. from the Paris Climate Agreement, or signing legislation to overturn rules and policies designed to stop coal mining, President Trump continues to fight for miners every day,” she said. Trump also signed legislation in February reversing an Obama administration rule to protect streams from coal mining waste.
Section 202(c) of the Federal Power Act allows the energy secretary to order power plants to operate for reliability reasons during emergencies.
The section has been used infrequently, notably during the Western Energy Crisis in 2000 and after Hurricane Katrina in 2005.
But attorneys for Latham & Watkins observed that the Energy Department “has interpreted its potential application broadly,” defining as an emergency “an unexpected inadequate supply of electric energy” and “regulatory action which prohibits the use of certain electric power supply facilities.”
In April, the department invoked 202(c) as a so-called “reliability safety valve” to keep the Grand River Dam Authority’s Grand River Energy Center Unit 1 running despite its failure to meet the requirements of EPA’s Mercury and Air Toxics Standards (MATS). GRDA had planned to replace Unit 1 with power from MATS-compliant Units 2 and 3, but Unit 2 was idled by a lightning strike and construction on Unit 3 was delayed by flooding. The order authorized GRDA to operate Unit 1 as needed to provide reactive power support until replacement generation capacity is available around the Grand River.
In June, the department used 202(c) again to authorize Dominion Energy Virginia to operate Yorktown Units 1 and 2 when PJM determines they are needed for reliability. The order stems from Dominion’s difficulty in gaining approval for a 500-kV transmission line across the James River. (See DOE Approves Emergency Dispatch of Yorktown Units.)
The Energy Department’s grid study included use of the emergency declaration among the report’s recommendations for “further research.”
FirstEnergy: No Bankruptcy Decision Until Mid-2018
But the company on Monday denied Murray’s claim that a bankruptcy filing for FES is imminent.
“Bankruptcy of FirstEnergy Solutions, the company’s competitive subsidiary that owns the power plants, is one of the possibilities under consideration, but no decisions have been made at this time,” said FirstEnergy spokeswoman Jennifer Young. “We have previously indicated we expect to complete the strategic review by mid-2018.”
She said the company’s “strategic review” is exploring options, including “the possible sale of some competitive gas and hydro assets; legislative efforts to move some competitive assets to regulated or regulated-like constructs; seeking a solution for nuclear units that recognizes their environmental benefits; the sale of other generating assets; or additional deactivations.”
CARMEL, Ind. — While a MISO workshop last week fell short of defining potential market rules for energy storage devices, it did provide stakeholders an opportunity to hash out their thoughts on a technology that straddles the boundaries between generation and transmission.
During the RTO’s first energy storage workshop last month, stakeholders advised it to consider all the capabilities and types of battery storage before drafting market rules and creating definitions. (See MISO Rules Must Bend for Storage, Stakeholders Say.)
At the second — and likely final — workshop Aug. 24, MISO took a stab at providing structure for addressing the complex issue by suggesting which committees should field various storage proposals.
MISO assigned Chief Compliance Officer Joseph Gardner to serve as its liaison to the newly created Energy Storage Task Force, which will gather ideas that could eventually become proposals at the Resource Adequacy Subcommittee, Market Subcommittee, Reliability Subcommittee and Planning Advisory Committee.
The RTO suggested that the PAC could handle storage interconnection methods and possible transmission cost recovery, while the MSC would tackle compensation rules. Either the MSC or RSC could work on the creation of no-harm tests, operating traits and market participation models, while the RASC could undertake capacity accreditation rules, said MISO Executive Director of External Affairs Kari Bennett.
But discussion at the workshop focused on the beguiling and intriguing issues around storage — and how to accommodate the increased adoption of a resource that defies MISO’s current market categories. The RTO currently has about 140 MW of battery storage requests in its interconnection queue.
Lin Franks stressed the future importance of storage resources in MISO, saying she’s become a battery convert since volunteering to head the energy storage division at Indianapolis Power and Light.
“I feel like I learn something new about these things every day,” Franks said. “Like I said, I’m a born-again Christian when it comes to batteries. They can solve problems, and solve them quickly.”
IPL’s Harding Street Station was MISO’s first battery storage facility, commencing operation in May 2016. The facility can continuously deliver 5 MW for more than four hours, as well as move from a neutral state to full injection or withdrawal of energy in under one second. It serves only primary frequency response, reacting to unanticipated deviations.
“The faster you can solve the [frequency] degradation, the fewer megawatts you need,” Franks said.
Like all grids, MISO’s system was designed with control in mind, Franks said. Recent additions of rooftop solar and wind generation can erode that control, but autonomous storage resources can mitigate those risks and provide more resilience.
“We like to talk about storage as one kind of animal, but it’s not. It’s a whole zoo of animals,” Franks said. “When I talk about my lithium ion battery, that’s not what all lithium ion batteries are like. They morph with the industry. They’re like a giant Lego set.”
Franks urged stakeholders to educate themselves on stored energy resources.
“Real-time operators don’t like change. They know what works and they’re comfortable with it. … Just like you, I see some arms crossed out there,” Franks said, teasing the audience.
Franks noted that MISO and state and federal agencies are still working out policy details around storage, including capacity accreditation, facilities agreements, state-of-charge management, interconnection conditions, removal of Tariff barriers and clarification of state versus FERC jurisdiction. She also recommended that MISO lay out an “expedited path” in its annual Transmission Expansion Plan for storage resources.
Franks recounted the confusion Harding Street caused upon entering MISO’s interconnection queue in 2014.
“None of us knew how to model these at the time,” she said, adding that the RTO eventually settled on modeling the battery at its maximum injection and withdrawal.
Each of the storage array’s eight 2.5-MW cores contain more than 20,000 data points captured every two seconds and used to manage the state of charge, which IPL currently handles. But state-of-charge management could be passed to MISO.
“There is the perception among some at FERC that having the RTO manage the state of charge creates a conflict of interest,” she added.
‘Slicker than Snot’
Stakeholders asked MISO officials how its markets could permit storage to serve two masters ― generation and transmission services.
RSC Chair Tony Jankowski, manager of electric system operations at We Energies, wondered how MISO could possibly allow a storage resource to switch between participating as a generating asset or a transmission asset using the RTO’s existing “clunky” market process.
“These things are slicker than snot and can do a lot of things in a very short period of time,” Jankowski said, adding that MISO might accommodate the chameleon-like nature of storage with an “either/or” asset registration.
Indiana Utility Regulatory Commission staffer David Johnston said asset registration raises a question of whether storage resources must enter the RTO’s generation interconnection or the MTEP process.
“I think these are all good questions,” said MISO Director of Planning Jeff Webb, who added that he could not yet venture a guess as to the solutions. One of his concerns is keeping enough available capacity on hand if storage can register as both capacity and transmission assets.
“But none of these [questions] are showstoppers. It’s just how to manage them,” Webb said.
“Whatever the process, I don’t want to halt the progress of these Lego blocks, as Lin called it,” said DTE Energy’s Nick Griffin.
Multiple stakeholders said MISO’s storage models must account for every kind of storage, from the more common battery storage to flywheel to compressed air to pumped storage.
Griffin pointed out that MISO is years away from modeling storage as both a transmission and generation resource. However, Jankowski pointed out that storage modeling could be simplified by distinguishing between synchronous and inverter connections.
Some stakeholders said collection of storage information is the key to creating participation models, but Customized Energy Solutions’ David Sapper said he would play the “contrarian” and caution about information overload. Sapper pointed to the risk of micromanagement through extensive communications and controls, an issue raised by University of Wisconsin engineering professor Bob Lasseter at the Organization of MISO States’ distributed energy resources workshop earlier this month. (See Stakeholders Hash out Future of DER at OMS Workshop.)
While Franks agreed, she countered that a lot of information may be necessary at the onset of market storage participation.
“This is new to [MISO operators], and until they get comfortable, they’re going to want to see more than less — and that may not take very long,” she said.
American Transmission Co.’s Bob McKee said it would be helpful for MISO to create a price menu showing the current compensation provided for possible storage-sourced services like energy arbitrage and frequency response.
“I think it’s fair to say if we did that now, we’d have a lot of question marks in there,” Bennett said.
“That’s fine. This [menu] would tee that up,” McKee said, and other stakeholders agreed.
Westar Energy will pay a civil penalty of $180,000 for submitting inaccurate mitigated energy offer curves (EOCs) under a settlement with FERC’s Office of Enforcement.
Westar also agreed to be subject to Enforcement monitoring under the settlement, which was approved by FERC on Thursday (IN15-8). The Kansas utility will submit annual compliance monitoring reports for two years, with a third year possible at the office’s discretion.
The violations occurred between October 2014 and February 2015, when Westar submitted cost inputs three times for its State Line plant that FERC said were “inconsistent” with the cost parameters on file with SPP’s Market Monitoring Unit. The incorrect data resulted in the utility receiving make-whole payments of about $60,000.
Westar’s State Line facility | Westar Energy
The MMU requested in March that Westar produce data validating its mitigated EOCs. It found the data insufficient and referred the company to Enforcement.
Mitigated EOCs in the RTO’s Integrated Marketplace must be based on an individual resource’s costs and unit characteristics. They are generated according to a formula that contains several inputs, including a fuel cost adder for variable operations and maintenance (VOM) costs.
Enforcement’s investigation determined a Westar employee inadvertently increased the fuel VOM charge from 5 cents to 50 cents for the company’s share of the two State Line units. Staff also found the utility submitted incorrect heat rate coefficients for one of the units.
The utility voluntarily refunded the $60,000 to SPP in June 2015 and took “effective measures to identify mitigated EOCs that [it] failed to properly update,” FERC said.
The commission noted that the utility cooperated throughout the investigation and promptly responded to requests for data and testimony. The utility filed a detailed report in June 2015 explaining the origin of the errors, the steps taken to correct them and the plans implemented to prevent them in the future.
Westar is the largest electric company in Kansas, serving 690,000 residential, commercial and industrial customers in the eastern third of the state.
FERC on Wednesday again rejected a request that it include the cost of emissions controls in the peaking plant design for the New York Control Area (NYCA) capacity demand curve (ER17-386).
The commission rejected a rehearing request by the Independent Power Producers of New York (IPPNY), which contended that the state’s Siting Board is likely to require selective catalytic reduction (SCR) emissions controls in the future because of concerns over fossil fuel generation.
FERC repeated its conclusion that SCR controls are not required for peaking plants in NYCA load zones C and F and that peakers can meet environmental rules by limiting their operating hours, dismissing as “speculative” IPPNY’s prediction of tighter controls in the future.
IPPNY had asked the commission to reconsider its January ruling approving NYISO’s revised demand curve for delivery years 2017/18 through 2020/21. (See FERC OKs NYISO Demand Curve Reset.)
The January order continued the use of F class frame peaking turbines as the proxy unit for setting the cost of new entry. It also continued the requirement that peaking plants include dual-fuel capability and SCR emissions controls for the New York City, Long Island and G-J Locality demand curves.
| Analysis Group
But the commission rejected the ISO’s proposal to extend the SCR requirement to the NYCA, where gas-only designs were permitted. Under current rules, FERC said, the NYCA peaking plant can operate under an annual operating hours limit in lieu of installing SCR emissions controls.
In its order this week, FERC also rejected IPPNY’s request to shorten the amortization period or increase the rates of return for peakers in zones C and F. IPPNY said the changes would capture the risk that emissions rules on those plants will be tightened in the future.
The commission deemed as “speculative” the risk of having to retrofit an NYCA peaking plant with SCR controls, and also found NYISO’s proposed amortization period and return on equity to be just and reasonable.
“The commission need not consider alternatives,” FERC said. “Nevertheless, IPPNY provides no alternatives, but only a scant statement that the commission should impose either ‘a significantly shorter amortization period than the NYISO’s proposed 20-year period or an increased required return.’ In contrast, NYISO’s amortization period and return on equity were the subject of analysis by [the ISO’s independent consultant] and extensive stakeholder discussions.”
FERC last week approved Pacific Gas and Electric’s request to recover from its customers a portion of the costs of a $1.8 billion package of planned transmission improvements if the company is forced to abandon construction for reasons beyond its control.
The commission approved abandonment cost recovery for only some of the substation improvements and transmission lines that PG&E plans to construct (EL16-47). It also ruled that the utility is eligible for a 50-basis-point adder to its base return on equity as an incentive because the improvements are part of a regional transmission planning process.
The California Public Utilities Commission objected to PG&E’s proposals, saying the company had not demonstrated the improvements would relieve congestion and had not provided enough information on the scope of the projects. PG&E was not transparent about cost control, projects costs had escalated since CAISO’s approval and the utility had failed to quantify the possible abandoned plant cost to ratepayers, the PUC argued.
The PUC also contended that PG&E failed to disclose in CAISO’s competitive solicitation process that it intended to seek from FERC incentive rate treatment for the projects.
The Sacramento Municipal Utility District, Transmission Agency of Northern California and the Six Cities group also protested the incentives.
FERC disagreed, saying “the CPUC does not point to any commission order or provision of the CAISO Tariff requiring project sponsors to disclose, in advance, that they intend to seek transmission rate incentives for their respective projects from the commission.”
Public utilities can seek incentive-based rates for projects that preserve reliability or reduce delivered power costs by reducing congestion. To get the incentive and additional profit, PG&E must participate in a regional transmission planning process, which it does through CAISO.
The commission also held that PG&E was entitled to the rebuttable presumption that each of its projects would either increase reliability or reduce congestion because they were approved through CAISO’s FERC-sanctioned transmission planning process.
Among the Improvements are new Substations
The projects listed in PG&E’s petition to FERC are the Wheeler Ridge substation; Northern Fresno 115-kV reinforcement; Midway-Andrew 230-kV project; Estrella 230/70-kV substation; Lockeford-Lodi Area 230-kV development; Martin Bus 2-kV bus extension; Oro Loma 70-kV reinforcement; and Spring 230-kV substation.
FERC approved PG&E’s requests for abandoned cost recovery for the Wheeler Ridge, Northern Fresno and Midway-Andrew projects but denied them for the others. The approved projects met FERC’s standard for a “nexus test” based on project scope and regulatory and construction risk because of land acquisition and other factors.
The commissioned also denied the company’s request for recovery of costs incurred up to the point of its March 10, 2016, filing.
