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.
The nuclear industry hopes the grid study released by the U.S. Energy Department last week will accelerate RTO price formation efforts valuing baseload generation and that the federal government will begin purchasing nuclear power.
But states are still the first line of defense against premature plant closures, the Nuclear Energy Institute said at a press conference Thursday.
“We see the nearest-term opportunities for action to be at the state level while the RTOs and FERC [are] a little bit further out,” said John Kotek, NEI’s vice president for policy development and public affairs.
Kotek, a former DOE official, praised his former colleagues for what he called a “solid, fact-based, dispassionate analysis of the issues facing today’s electric grid.” (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
“We know that states are more nimble in their ability to respond to the challenges immediately in front of them,” agreed Matt Crozat, NEI senior director of policy development and another ex-DOE staffer.
He also urged Congress to exercise its oversight authority to ensure prompt action by FERC and RTOs on price formation rules.
“I think FERC can create the requirement to demonstrate how the [RTO] tariffs reflect these attributes that are important to the system,” he said, adding, “I’ll be watching closely to see how FERC begins to frame the question for itself.”
“Based on what we’ve heard out of FERC leadership, it does sound like they’re poised — it sounds like the system operators are poised — to actually move out fairly smartly on these things,” Kotek said.
In a podcast interview with FERC’s chief spokeswoman earlier this month, acting FERC Chair Neil Chatterjee said, “Baseload power … including our existing coal and nuclear fleet, need to be properly compensated to recognize the value they provide to the system.” He cited their value to “resilience and reliability.”
NEI also noted the DOE report’s reference to the “important nonproliferation” implications of allowing the industry to decline.
DOE quoted Michael Webber, deputy director of the University of Texas’ Energy Institute, who cited the risk to “our most important anti-proliferation asset: a bunch of smart nuclear scientists and engineers…. The loss of expertise from a declining domestic nuclear workforce makes it hard for Americans to conduct the inspections that help keep the world safe from nuclear weapons.”
NEI officials saod they hope federal officials will consider making power purchase agreements from nuclear plants like the ones military bases with renewable power developers during the Obama administration.
“Those types of arrangements were clearly struck both to meet electric demand but also to promote, in this case, the growth of renewable energy deployment across the United States,” Kotek said. “If we as a nation determine that the national security benefit of a strong domestic nuclear industry, along with the clean air benefits and the resiliency and reliability of nuclear plants are worth keeping around, then that’s one avenue you could pursue in the effort to ensure we retain the plants that we’ve got.
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
“And it’s a potential means for building new [plants],” Kotek continued. “You may know [that] the sustainability order that was put in place by the last administration included small modular reactors, for example, as a technology that would qualify as meeting clean energy demand going forward. It’s one … potential tool in the tool box.”
The officials cautioned against attempting to precisely price resiliency attributes into wholesale power markets.
“I think there are more expansive ways to go at this question without having to necessarily settle on ‘Reliability is worth $4/MWh’ or something like that,” Crozat said. “That’s going to be a difficult calculation to derive.”
Crozat said he was encouraged by PJM’s June report proposing to allow nuclear and coal plants needed for reliability to set clearing prices based on their marginal costs. This would be particularly helpful in addressing negative clearing prices in off-peak hours, he said. (See PJM Making Moves to Preserve Market Integrity.)
“If I know I have units that are going to be needed for reliability, I’ll ensure that the prices are being set in a way that recognized the cost of those units,” he explained. “It just changes slightly the economic logic of who’s allowed to set prices and who isn’t.”
Exelon, the nation’s largest nuclear operator, said it was encouraged by the Energy Department’s recommendation that FERC “expedite” its efforts to improve energy price formation in organized wholesale markets. The company is defending zero-emission credits for its plants in New York and Illinois.
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
“These reforms will help preserve clean energy sources and ensure critical American assets remain part of the mix, including baseload nuclear plants that provide more than 60% of our nation’s emissions-free energy,” the company said in a statement. “We applaud the Department of Energy for their work, and urge FERC and the RTOs to swiftly enact common-sense reforms that will help safeguard the reliability, resilience, diversity and affordability of our supply of electricity.”
NRG Energy, one of the independent power producers that have fought ZECs, also urged FERC to act on price formation and provide fuel- and technology-neutral ways to value reliability services.
“These efforts — and not expensive and market-destroying state subsidy programs to benefit particular generating facilities — would do more than anything else to ensure resiliency and reliability in an environmentally responsible and consumer-friendly way,” the company said in a statement.
NERC staff told SPP’s registered entities Friday they have until Oct. 31 to submit their transfer requests to another Regional Entity, following the dissolution last month of the RTO’s RE. (See SPP to Dissolve Regional Entity.)
Requests may be submitted by an individual entity or as part of a group, staff said. NERC is working with the 120 registered entities within SPP’s footprint to smooth their transfer to new compliance enforcement authorities, with ReliabilityFirst, Midwest Reliability Organization and SERC Reliability seen as the most likely landing spots.
| NERC
Registered entities should provide in their requests the location of their bulk power facilities, their relationship to their desired RE and their views on the proposed destinations for other entities in their regions. The regulatory authority will provide a weekly list of questions and answers to SPP’s registered entities, along with other materials.
“An entity does have the ability to request the NERC Board [of Trustees] reconsider a move if they don’t agree with it,” NERC General Counsel Charlie Berardesco said during a webinar for the SPP RE’s members.
Berardesco said registered entities must meet all obligations during the transition period, including compliance with reliability standards. Pending approval by NERC’s board and FERC, the SPP RE will cease to exist by the end of 2018.
Sempra Energy has wasted little time getting to know Texas stakeholders, embarking on a “listening tour” just days after its surprise announcement it was seeking to acquire the state’s largest utility, Oncor.
“We’re approaching North Texas with a fair amount of humility,” Sempra CFO Jeff Martin told financial analysts Friday during a conference call.
Martin and Sempra CEO Debbie Reed conducted the call from a hotel room in Austin, Texas, taking a break from meeting with Texas regulators, intervenors and other key Sempra and Oncor stakeholders.
The San Diego-based company last week announced an agreement to acquire Energy Future Holdings, Oncor’s bankrupt parent and indirect 80% owner, for $9.45 billion, besting Berkshire Hathaway Energy’s $9 billion offer. (See Sempra Outmuscles Berkshire for Oncor.)
Sempra had been eyeing Oncor for several years, but “this deal came together very quickly,” Reed said. Company staff have been reviewing the history and transcripts of previous proceedings before the Public Utility Commission of Texas, which denied previous attempts by Hunt Consolidated and NextEra Energy to acquire the utility. The PUC rejected both suitors because of their inability to meet strict ring-fencing measures put in place after EFH declared bankruptcy in 2007.
“We tried to listen and learn from prior transactions, and we’re working to understand the issues that are important to the regulators and intervenors,” Reed said. “We intend to be a long-term owner of Oncor and want to ensure the company continues to do an exceptional job meeting the needs of its customers.”
Reed pointed to Oncor’s “incredible history of success,” its ability to pay dividends and recent completion of a rate case as reasons for Sempra “to get comfortable with the requirements that the regulators had put on in prior transactions.”
Those requirements have included an independent board of directors, a continued Texas presence and reinvestment of capital expenditures.
“If Oncor needs those funds to invest in their business, we are very supportive of that because we see the utility investment is positive,” Reed said, referring to Oncor’s plans to spend about $7.5 billion in capital over the next five years.
“We’re all about partnerships and making sure that from a stakeholder analysis standpoint, we’re doing all the right things to address those concerns,” Martin said. “We’re just starting that process, and we’re confident about telling our own story. I think we’re comfortable with a lot of the issues that have been raised with us.”
However, some intervenors in Oncor’s prior proceedings are skeptical of Sempra’s offer, a source told RTO Insider. BHE had reached a settlement agreement with key intervenors based on its ability to wipe out the utility’s debt overhang with an all-cash deal, but those parties now complain that Sempra is providing very little information in what has been called a “half-baked” proposal.
Sempra executives said Friday that they intend to fund the $9.45 billion purchase with $3 billion of investment-grade non-course debt, with the company providing about 60% of the remaining $6.45 billion and third-party investors covering the rest.
Martin said Sempra is not considering EFH’s current creditors or hedge funds; instead, it is looking to partner with investors that are “aligned with our long-term interest in reinvesting and growing Oncor,” such as pension or infrastructure funds. He said the company plans to issue a combination of debt and equity to fund its 60% portion, with equity representing at least half that.
Sempra agreed to a $190 million termination fee, compared with BHE’s $270 million fee.
The California company now faces two important regulatory hurdles. The U.S. Bankruptcy Court for Delaware will consider the merger agreement Sept. 6, followed by a hearing to confirm EFH’s reorganization plan. That second hearing would take place about 30 days should the PUC approve Sempra’s offer. Reed said Sempra plans to file with the commission shortly after the merger agreement is approved.
The PUC meanwhile last week sent Oncor CEO Bob Shapard a letter asking him and board Chair Jim Adams to appear at Thursday’s open meeting in Austin.
The commission told Shapard it wants to discuss Oncor’s views “as to the likely structure and timing” of Sempra’s proposal, and the utility’s current financial condition and liquidity as it relates to the PUC’s “legal obligation to protect” the company’s financial integrity. The commission said it also wants to delve into accrued expenses over the last two years as a result of the Hunt and NextEra acquisition attempts.
