Exelon announced Tuesday it has purchased the James A. FitzPatrick nuclear plant for $110 million from Entergy.
Officials from both companies were joined by Gov. Andrew Cuomo at the plant’s gates to announce the deal, which is subject to regulatory approval.
“We are pleased to have reached an agreement for the continued operation of FitzPatrick,” Exelon CEO Chris Crane said in a statement. “We look forward to bringing FitzPatrick’s highly skilled team of professionals into the Exelon Generation nuclear program, and to continue delivering to New York the environmental, economic and grid reliability benefits of this important energy asset.”
Entergy executives had reiterated last week that the company did not intend to continue operating the troubled plant in upstate New York beyond January 2017.
“There are no plans to continue to run the plant under Entergy ownership,” Bill Mohl, president of Entergy Wholesale Commodities, told analysts during the corporation’s second-quarter earnings call Aug. 2.
Fitzpatrick Nuclear Plant Source: Entergy
The company had announced plans to shut down both FitzPatrick and the Pilgrim nuclear plant in Massachusetts, but it recently said it had opened negotiations with Exelon over FitzPatrick. (See Entergy in Talks to Sell FitzPatrick to Exelon.)
Mohl told analysts if Entergy and Exelon are able to gain regulatory approvals for the transaction, refueling activities would begin in January. Otherwise, the decommissioning process would begin instead.
“We’ve made a commitment to reduce the size of the EWC footprint,” Mohl said. “If we’re unable to reach commercial agreements with Exelon or we’re not able to achieve those regulatory approvals, we’ll begin the regular decommissioning process and stay on the same path that we have previously been on.”
New York’s Public Service Commission on Aug. 1 unanimously approved 12-year subsidies for the state’s nuclear power plants on Lake Ontario, which have been buffeted by market forces. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
Entergy reported second-quarter net income of $572.6 million ($3.11/share). That beat analyst expectations of $1.05/share, as polled by Thomson Reuters.
Revenue dropped to $2.46 billion, from $2.71 billion in the second quarter of 2015. The company said its March purchase of a 1,980-MW natural gas plant in southern Arkansas helped support revenue during the quarter.
Company shares, up 18.9% this year before the earnings announcement, have dropped 94 cents since, closing at $80.33 on Aug. 3.
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week rejected a request to allow economic dispatch of reliability-must-run (RMR) units over the objections of the ISO’s Independent Market Monitor and several of its Houston-area market participants.
NRG Texas drafted nodal protocol revision request 784, which addresses how RMR units are priced and dispatched, about the same time as ERCOT made its recent decision to extend into 2018 an RMR contract for NRG’s Greens Bayou Unit 5 near Houston.
The contract requires ERCOT to pay $3,185/hour for the duration of the agreement and an incentive factor of as much as 10% to reserve the 371-MW gas-fired unit’s capacity during summer months through June 2018. (See “Board Expands Greens Bayou RMR Contract to 2018,” ERCOT Board of Directors Briefs.)
NRG’s request would allow security constrained economic dispatch of RMR units to relieve transmission congestion after all other capacity available for transmission congestion relief had been exhausted.
Market Monitor Beth Garza supported the proposal, which she said would increase the dispatch price of RMR units, allowing other market units to be dispatched to resolve the constraint first.
In ERCOT’s energy-only market, an RMR agreement results from either a poorly designed evaluation process — which mistakenly identifies a resource as needed — or a failure of the market to provide sufficient revenue to justify continued operation of a needed resource, she said.
“Should the failure be in the RMR designation process, the resource is unlikely to be deployed and its energy offer price will be immaterial,” Garza said. “However, if the failure is in the market signal to units in this constrained area, the unit is likely to be deployed and the energy offer price will matter.”
Bill Barnes, NRG Energy’s director of regulatory affairs, said the request underscores the importance of sending the right price signals in the ERCOT market.
“We’re spending $60 million on an RMR contract for the months of June, July, August and September,” he said. “When you look at the State of the Market report for 2015, the real-time congestion rent for three of the major north-of-Houston constraints is $5 million. We’re spending $60 million to solve a $5 million problem. There are legitimate situations where the market solves the problem in a cheaper way. The boogeyman that is high prices gets pummeled by the boogeyman that is RMR.”
As drafted, NPRR784 would only apply when generator offers are mitigated because there is inadequate competition. RMR units are currently subject to the same offer mitigation as other units in such a situation, with Greens Bayou Unit 5 likely being offered at around $50-60/MWh. When there is adequate competition, RMR units are offered at $9,000/MWh under either the status quo or the NPRR.
The revision request would instead require all RMR units to be offered at the highest possible price that would still allow SCED to dispatch the unit for congestion. In Greens Bayou’s case, the estimates are as high as $700/MWh.
The NPRR failed to gain the Protocol Revisions Subcommittee’s endorsement during a roll-call vote July 14, but NRG appealed to the TAC. The revision request eventually fell short of the necessary two-thirds approval, with 54% positive votes and four abstentions.
NRG on Friday filed another appeal with the Board of Directors, which will consider the proposal at its Aug. 9 meeting.
“How do you prevent future RMR? By sending the right price signals,” Barnes said. “The presence of the RMR is evidence the market signal has failed. 784 addresses the most important RMR issue: How do you send the right price signal? It’s not a perfect solution, but is it better than what we have today? We believe the answer is yes.”
Garza supported Barnes’ position, although she also said she is a “huge believer” in ERCOT’s stakeholder process and “what this room can do.”
“Our position has been the objective of the RMR should be the price should be reflective of the unit not being there, but we should have the energy available to resolve the constraint,” Garza said. “It is absolutely a shortage condition. If that situation did not exist, Greens Bayou would be on the way to the scrap heap right now.
“I’m sympathetic to the argument that, ‘Gosh darn it, we spent $60 million on this unit, why can’t we use it?’” Garza said. “However, believe it or not, those are sunk costs … that don’t change if you resolve this situation. When you’re talking about resources necessary to resolve a transmission constraint, there are two factors: the offer price or mitigated offer cap, and the shift factor of the unit on that constraint — the effectiveness of that unit to relieve the constraint.”
“We generally agree with the IMM … but we disagree that 784 as a one-off is the solution,” said Energy Future Holdings’ Amanda Frazier, chair of the PRS. “We’re concerned [NPRR784] is reactionary. It doesn’t address whether Houston prices are high enough to allow RMR. If we pass this, we’re paying for incorrect price signals.”
Katie Coleman, with the Texas Industrial Energy Consumers group, represented the PRS position, arguing NRG’s proposal is punitive to loads, encourages unit retirements by providing scarcity pricing in non-scarcity conditions and prevents the RMR unit from solving other constraints beyond a single transmission line.
“We have concerns about requiring loads to also pay $600-800/MWh to use that unit for the very purpose it was placed under an RMR contract,” she said. “We have concerns about the incentive this creates for a generating company with a fleet of units in a certain area to retire units and get high pricing for its other units. [NPRR784] would require Greens Bayou to be priced at the highest possible price to solve, which would preclude it from solving other constraints in area.”
Noting that the revision request has been classified as urgent, Coleman said that electric retailers are concerned its requested September implementation timeline does not provide enough lead time for Greens Bayou and other generators in the area.
Coleman also noted customers are paying for Greens Bayou only until the Houston Import Project goes into service as early as 2018, when it is expected to solve the region’s congestion issues.
“This NPRR is sending a price signal too late to matter,” Citigroup Energy’s Eric Goff said. “The fact the contract exists is interfering with what would happen had the unit been allowed to retire. It gets to the point of whether there’s a weird incentive here.”
“If you’re a load outside of Houston, I have no idea why you’re not outraged,” Barnes said. “If the load in Houston has a small load-ratio share, I can understand why you would want someone else to solve your problem. We’re an energy-only market. Price signal is everything.”
Shortly after the TAC meeting concluded Thursday, ERCOT posted answers to questions it received from its request for proposals for must-run alternatives to the Greens Bayou RMR contract. (See ERCOT Seeks Alternatives to Houston-Area RMR Unit.)
Committee Discusses July 7 System Outage
ERCOT staff shared its analysis of the July 7 outage of its Energy Management System. The outage lasted 102 minutes and resulted in corrupted data being passed to downstream systems, including settlements and reports. Market participants said they saw a perceived drop-off in load and generation, but their primary complaints were around a lack of information coming from the ISO.
“When these things are occurring, I know ERCOT is scrambling to recover and get the grid stable again,” Barnes said. “From a market perspective, it was pure chaos. Market notices should be crystal clear about what is happening.”
“We just knew something was wrong because of operation notices,” Goff said. “Knowing the extent of the outage would be beneficial to the market.”
“We want to share with you the information we definitively know as quickly as possible,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “The tension we’re trying to balance is how long to hold information back until we can be sure” it’s accurate information.
The problem began at 11:41 a.m., when an operator mistakenly loaded test data into the active system, which corrupted data in the emergency system’s network model. Between 11:59 a.m. and 12:16 p.m., the market’s qualified scheduling entities were instructed to assume constant frequency control. By 1:23 p.m., the data had been corrected and verified, and operations returned to normal.
Corrected prices were posted for the affected SCED intervals, and staff said that it is continuing to evaluate alternatives that may affect subsequent settlements.
Barnes was successful with a second NPRR, dealing with ERCOT’s price-correction process following a SCED failure. NPRR696, which Barnes drafted on behalf of NRG subsidiary Reliant Energy Retail Services, passed with 72% of the vote.
“When the SCED system is not running, inputs grow stale. When it starts back up, things don’t make sense,” Barnes said. “It comes down to whether you believe the last best price, or whatever it spits out.”
NPRR696 establishes a price-correction policy that uses the last good price for settlement until ERCOT no longer requires manual action to stabilize the system. Barnes said that correcting prices for settlement intervals corresponding to the active watch period would give market participants transparency to known prices that reflect the last good SCED execution.
“This policy would extend that last good price for another 15 minutes,” Barnes said. “It could be the last high price or the last low price.”
The TAC unanimously endorsed six other NPRRs, a system-change request (SCR) and revisions to the Nodal Operating Guide (NOGRR), the Planning Guide (PGRR), the Retail Market Guide (RMGRR) and the Resource Registration Glossary (RRGRR).
NPRR738: Excludes from performance calculations intervals when an emergency response service generator is unable to meet its obligations because of transmission/distribution service provider (TDSP) outages.
NPRR747: Proposes new definitions related to voltage profiles, defines various entities’ responsibilities related to voltage support and clarifies that the interconnecting transmission service provider or its designated agent may modify a generation resource’s voltage set point.
NPRR767: Changes the eligibility check for the startup portion of the reliability unit commitment make-whole payment. Resources with lead times longer than six hours may submit a settlement dispute to have their resource-specific startup times considered when determining eligibility for startup costs included in the make-whole payment calculation.
NPRR770: Adds visibility and situational awareness to the market by posting the aggregate number of telemetered resources and their statuses to the ancillary service capacity monitor.
NPRR771: Clarifies that TDSPs must ensure an electric service identifier has been created in ERCOT systems before initiating electric service at a premises, avoiding related transactional, billing and out-of-sync issues.
NPRR774: Removes duplicate language regarding the calculation of seasonal transmission-loss factors.
NOGRR155: Clarifies voltage ride-through performance requirements for all generation resources immediately following a fault, stipulating that they must remain online and connected to the transmission system, and also maintain real power.
PGRR046: Aligns the planning guides with NERC’s TPL-007-1 reliability standard related to geomagnetic disturbances by specifying a process for developing geomagnetically induced system models.
RMGRR138: Removes the requirement for retail electric providers serving pre-pay customers to provide a weekly list of electric service identifiers to Oncor, replacing it with the requirement to provide the prepay list upon Oncor’s request.
RRGRR009: Adds three categories of data: voltage limits for resources’ substation transmission level equipment; geomagnetically induced currents and the presence of blocking devices to allow for the study of any vulnerability attributed to geomagnetic disturbances; and a most limiting single element (MLSE) allowing a resource entity to identify an MLSE on lines it doesn’t own.
SCR789: Updates the Network Model Management System topology processor to add a software tool commonly used by transmission-planning entities in ERCOT.
MISO and PJM are seeking to hammer out new joint operating agreement language that would allow accelerated approval of short-term projects intended to relieve congestion at the RTOs’ seams before advancing further on a joint study that would identify potential projects.
MISO engineer Adam Solomon said that while the RTOs continue to work on the language detailing joint targeted market efficiency projects (TMEPs), the JOA needs to have a vetted process in place before project selection begins.
“We should really have the JOA language worked out before we push further into the study,” PJM engineer Alex Worcester agreed during a July 29 meeting of the MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC).
Targeted MEPs will differ from ordinary MEPs, which undergo a “longer and more rigorous” review that combines regional approval, modeling and analysis, and a review timeline. MEP rules may also be changing as a result of a FERC order requiring the RTOs to revise their interregional approval processes. (See MISO, PJM Working to Comply with NIPSCO Order.)
The two RTOs are currently evaluating 13 potential small projects in Illinois, Indiana, Michigan and Ohio.
“We’re really looking for the small, low-cost, short lead time projects that alleviate historical congestion at the seam,” Worcester said.
“We’re reviewing the upgrades and we’re working to ensure they’re effective and alleviate congestion,” Solomon said.
Officials from both RTOs said construction of the small projects could begin before the end of the year. That would require a special approval process developed within “a very tight timeline,” said Worcester, adding that the JOA should set out a simple method for TMEP approval.
The JOA stipulates that TMEPs must be in service within three years and cost less than $20 million. Projects exceeding the cap would move to the MEP classification. Because of the near-term nature of TMEPs, inflation rates will not be factored into the cost-benefit calculation.
MISO and PJM also propose to replace the current 1:1 cost-benefit ratio with a requirement that TMEPs produce enough benefits to cover their costs within four years.
“It’s a pretty high hurdle for these projects to pass,” Worcester said. “It’s consistent with our goal of having high-impact projects.”
To determine if a project meets the cost-benefit metric, the RTOs will rely on three years of historical congestion data to project a future case adjusted by market-to-market payments.
The new cost-benefit approach will “avoid complicated analysis,” said Worcester, who added that he could further illustrate the approach at the Aug. 26 IPSAC meeting.
The RTOs also want to be able to discount historical congestion at flowgates — used to determine TMEP project eligibility — by factoring in congestion hedges or auction revenue rights.
Worcester said that flowgates have an average of 30 to 40% of their flow hedged, but some flowgates have 100% hedging while others have zero. “What we’ve seen is a lot of variability from flowgate to flowgate,” he said.
Stakeholders are asked to provide feedback on the proposed TMEP language by Aug. 12. Final draft language will be presented at the Aug. 26 meeting.
“We’re making good progress toward getting this filed,” Worcester said.
NASHVILLE, Tenn. — Regulators from Connecticut and New Jersey last week urged their colleagues to join them in developing cybersecurity rules for electric distribution companies.
“Get in motion. Get started,” Arthur House, chairman of the Connecticut Public Utilities Regulatory Authority, told the National Association of Regulatory Utility Commissioners summer conference. “We have to attack it. It’s too important not to.”
In April, the state released a Cybersecurity Action Plan, which calls for a voluntary oversight program in which utilities would meet annually with state officials to report on their cyber defense programs, experiences over the prior year dealing with cyber threats and corrective measures they planned.
PURA said it will consider adding reviews by “objective, third-party assessors.” The New Jersey Board of Public Utilities issued more prescriptive rules in March requiring senior officers of distribution companies to certify their cyber protection plans, BPU President Richard Mroz said. The rules apply to natural gas, water and wastewater utilities, in addition to electric distribution companies.
The BPU requires the companies to define responsibilities for cyber risk management activities and establish plans for identifying and mitigating risks to critical systems. It also requires companies to provide cybersecurity awareness training and to report cyber incidents and suspicious activity to the agency.
House said it’s understandable that state regulators are reluctant to take on the issue. “There’s just too much work in this job already. We already have too much work to do,” he said.
NERC’s mandatory reliability standards cover only the Bulk Electric System, generally defined as transmission lines operating at 100 kV and above. (See FERC Refines Bulk Electric System Definition.)
Nevertheless, some state regulators see cybersecurity as the exclusive job of the federal government, House said.
House said he was dismayed to hear Exelon CEO Chris Crane say earlier in the NARUC conference that part of his company’s defense is an “air gap” between Internet-connected computers and the supervisory control and data acquisition (SCADA) system.
“I’ve never met a federal official who believes the air gap exists. We stopped hearing about it from private sector officials in utilities two years ago at least,” House said. “It certainly is an outdated reference to a rather discredited concept.”
On July 21, however, FERC issued a Notice of Inquiry seeking comment on the Critical Infrastructure Protection reliability standards for transmission control centers and whether the commission should require the separation of the Internet and industrial control systems (RM16-18). The notice also asked for input on application “whitelisting” practices to prevent unauthorized programs from running in control centers. (See FERC Orders NERC to Develop ‘Flexible’ Supply Chain Standard.)
House also disagreed with Crane’s description of the level of cooperation between government and industry. Crane, a member of the Electricity Subsector Coordinating Council, a liaison between the federal government and the power sector, said communication between the government and industry on cyber threats has improved greatly.
“It’s become much better in the last couple of years, having everybody around the table” — U.S. Cyber Command, the FBI and the departments of Defense, Energy and Homeland Security — “really working to communicate across the table much better. The silos are breaking down and the information is flowing.”
House disagreed.
“They’re not sitting at the same table. They’re not talking the same language,” he said. “We have goodwill [and] occasional cooperation. But we do not have an adequate defense system or adequate recovery” plans.
“There is a huge gap,” he continued. “I think we’ll have a partial compliance until we have an attack and then you’ll get mandatory standards” for EDCs.
FERC Commissioner Cheryl LaFleur said distribution companies and their regulators don’t need to wait for formal requirements. “There’s a lot that can be done at the distribution level without mandatory standards,” she said, noting that many distribution utilities are NERC registrants because of their transmission assets. “It’s not as if any of them are unaware of cyber challenges.”
LaFleur said the NERC standards approved by FERC rely on “defense in depth,” including perimeter security, virus screening and other measures. Every successful attack, she said, is the result of multiple failures.
On July 21, LaFleur dissented on a FERC order directing NERC to develop a reliability standard for supply chain management, saying the order failed to provide enough guidance and should have been delayed to allow more study (RM15-14-002).
Texas Public Utility Commissioner Ken Anderson said he worried the rule could create a “false sense of security.”
In 2011, he noted, Boeing and the Navy found that the ice detection system on a new P-8 Poseidon, a plane designed for long-range anti-submarine and anti-surface warfare and intelligence missions, was defective because it contained counterfeit components sold by a Chinese subcontractor.
“If the Pentagon — that actually has access to the intelligence — if they can’t catch the defective subcomponents going into a military weapons system … how the heck can a utility know what’s in that chain?” he asked.
FERC has granted the developers of the Constitution Pipeline an additional two years to complete the project.
The developers said they needed an extension while they appeal the denial by New York environmental officials of a required water quality permit under Section 401 of the federal Clean Water Act. (See Constitution Pipeline Appeals Rejection of Water Permit.)
FERC originally approved the project in 2014, with the condition that it be placed in service within 24 months. The extension gives developers a new deadline of Dec. 2, 2018. The pipeline would deliver Marcellus Shale natural gas from Pennsylvania to pipelines serving New York state and New England.
Waste Control Specialists began supplying the Nuclear Regulatory Commission more information about the company’s plans to store high-level nuclear waste in Andrews County, Texas, after a letter from the commission fueled opponent groups’ criticisms.
The letter from Mark Lombard, director of NRC’s division of spent fuel storage and transportation, told WCS that its application for the project was deficient and requested more technical data. Opponents said the letter reflected unpreparedness on the part of the company.
WCS officials responded by clarifying the company only wants a license to store spent nuclear fuel rods using a dry-cask design and method already approved by the commission. The company plans to store 5,000 metric tons in the first decade but is seeking approval to store up to 40,000 metric tons.
Tribe Sues Corps of Engineers Over Dakota Access Permits
The Standing Rock Sioux Tribe of North Dakota and South Dakota is suing the U.S. Army Corps of Engineers for issuing permits for a crude oil pipeline it says threatens sacred sites and its drinking water supply.
The suit, filed in a federal court in D.C., alleges that the Corps’ approval of the Dakota Access Pipeline is illegal, as it ignored risks to the environment and tribal sites. The pipeline, which would deliver North Dakota crude oil to terminals in Illinois, is being built by Energy Transfer Partners.
The Corps’ approval allows the developer to bury the pipeline under the Missouri River a half-mile upstream of the tribe’s reservation.
PSEG Files Opposition to Access Northeast with FERC
Public Service Enterprise Group has submitted a filing to FERC saying that a proposed natural gas pipeline expansion in New England would suppress wholesale prices in the energy market.
The company said the Access Northeast project, proposed by Spectra Energy and being subsidized by four New England states, is not driven by reliability needs, and the utilities that would own the pipeline would rarely use the gas. PSEG also compared it to a New Jersey plan to subsidize power plant construction in the state through the PJM capacity market, which was ruled unconstitutional by the Supreme Court as it infringed on FERC’s jurisdiction.
Critics of the PennEast Pipeline in New Jersey, however, said PSEG’s complaints could also apply to that project, which counts the company among its investors.
Nuclear Industry to NRC: Streamline Review Processes
A number of industry executives called on the Nuclear Regulatory Commission to improve the efficiency of its review processes, especially when it comes to approving advanced reactors.
“Anything you can do through the regulatory process to assure that the advanced reactors can come online as soon as reasonably possible, it’s going to be important not just for the United States, but for the world to meet this gap of increasing energy consumption,” former FERC Commissioner Philip Moeller, now senior vice president at the Edison Electric Institute, said during a public stakeholder meeting in Rockville, Md.
The meeting was the first of its kind since 1998. NRC was directed to hold it by Sen. James Inhofe (R-Okla.), chair of the Senate Environment and Public Works Committee, which has oversight over the commission.
DTE Energy raised its 2016 earnings per share guidance from $4.80-$5.05 to $4.91-$5.19 and said the addition of two new drilling rigs in the Utica Shale could boost profits further still.
Southwestern Energy Drill Rig Source: Southwestern Energy
Houston-based oil and natural gas company Southwestern Energy recently announced it will add five rigs by the end of the third quarter, two of which will be in the DTE-serviced Utica Shale basin, which could boost DTE’s gas storage and pipeline business segment.
The expected increase in drilling activity was excluded from DTE’s revised earnings guidance, which reflected better-than-expected second quarter results. But DTE CFO Peter Oleksiak said during an earnings call last week that the rigs “may provide upside to 2016” earnings and also will aid 2017 results.
DTE reported second-quarter operating earnings of $177 million ($0.98/share), up from $137 million ($0.76/share) in 2015. DTE’s gas segment earned $35 million, up $10 million from a year earlier.
NASHVILLE, Tenn. — Present and former regulators debated the costs and benefits of rooftop solar and the pros and cons of net metering in a spirited discussion at the National Association of Regulatory Utility Commissioners summer conference last week.
Charles Cicchetti, former chair of the Wisconsin Public Service Commission, and former Ohio Public Utilities Commissioner Ashley Brown led off the debate.
Cicchetti, a member of Pacific Economics Group and former economics professor at the University of Southern California, said regulators’ moves to curtail or reduce net metering payments and introduce new demand charges “greatly cut into the benefits that customers who installed rooftop solar expect to earn and use to pay for those systems.”
Cicchetti said regulators should require “vetted … neutral studies” to determine the costs imposed by solar customers and compare them with the benefits they provide.
“When you do that you’ll probably come away with the conclusion that, if anything, the extra costs that are being imposed by rooftop solar [are] far less than the extra benefits both in utility savings and societal benefits,” he said.
He said that time-of-use tariffs are more fair than demand changes, which he called “a blunt instrument.”
“If [rooftop solar customers] take electricity during expensive times, they should pay more. But they should also save more when they reduce electricity — as most of them do — during the time that those systems are operating.”
Brown, of the Harvard Electricity Policy Group, disagreed, saying solar customers under net metering are not paying their fair share of the system’s fixed costs.
The value of solar studies is incredibly subjective, Brown said. “Many states have done them; many interest groups have had them done and the findings are all over the map,” with some finding the value of solar is double the retail price and others finding a negative value. “Neither of those cases could possibly be true.
“Several things are always missing from these studies,” Brown continued. “One is, every single one of these values can be obtained from other sources. So why aren’t we disciplining the price we pay for those values by putting it into a marketplace with other sources? And many of these values are provided by other forms of generation who aren’t compensated for it because we don’t pay anybody based on value. We pay them based on market or we pay them based on cost.”
Nevada Public Utilities Commissioner David Noble spoke about the state’s bruising net metering battle last year, when the PUC conducted a ratemaking in response to a legislative mandate that rooftop solar result in “no unreasonable cost shifts.”
Noble said the commission was vilified by solar energy providers even though it rejected demand charges, implemented optional time-of-use rates and ordered a phase-in of “value-based” rates for excess energy.
“The rooftop solar companies decided to take an approach … that there should be no change from retail rates,” he said. “When you take an all-or-nothing approach, there’s a possibility that you’re going to lose. And that’s exactly what happened because they put on an inferior case.
“The CEO of SolarCity was claiming that he literally had a gun to his head and the commission was in the back pocket of” NV Energy, he said.
Solar companies bused hundreds of protesters to PUC headquarters, some of them exercising their open-carry rights to travel with guns, Noble said. There they attempted to alarm consumers by claiming utility rates would increase by 3% annually for the next 20 years.
“We haven’t had 3% increases year-over-year for any longer than three years,” he said. “In fact, over the last six years … rates have been flat in southern Nevada and they’ve gone down 20% in northern Nevada.”
Beverly Heydinger, chair of the Minnesota Public Utilities Commission, said the focus on net metering and rooftop solar is myopic, and that policymakers should also consider storage, electric vehicles and other emerging technologies.
“We’re not planning for today. We’re trying to develop a flexible enough template that we can use it and adapt as the times are changing,” she said.
RAPID CITY, S.D. — The SPP Board of Directors and Members Committee last week agreed to give transmission customers an extra 50 months to pay their Z2 bills while also creating a new task force to address complaints of members charged for costs that were not identified in service agreements.
The two actions illustrated the challenge of trying to ensure the equity of retroactively billing customers, the magnitude of the debts involved and the complexity of determining amounts to be billed and reimbursed under Tariff attachment Z2, which details how sponsors that fund network upgrades can receive reimbursements. Staff has identified $848.8 million in assigned costs from 158 creditable upgrade projects.
The board and members unanimously approved the Markets and Operations Policy Committee’s earlier recommendation to extend the Z2 payment timeline from 10 months to five years and dismissed waiver requests previously rejected by the MOPC. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)
Stakeholders also agreed to a suggestion by SPP CEO Nick Brown and directors Phyllis Bernard and Larry Altenbaumer directing MOPC Chairman Noman Williams to assemble a task force to find “a more rounded solution to this problem,” as board Chairman Jim Eckelberger put it.
The actions all but ensure there will be an additional recalculation of Z2 credits and bills in the near future.
“Does that mean there’s a round two coming? I believe it does,” Eckelberger said. “We’ve got to find a way to be as inclusive and equitable as [the process] can be. We need to get this right.”
The agreement short-circuited another contentious discussion on an issue that dates back to 2008, when SPP was to have begun crediting and billing customers for system upgrades in accordance with attachment Z2. Years of incorrectly applied credits have complicated the task of trying to accurately compensate project sponsors and claw back money from members who owe debts for the upgrades.
“We feel we are owed a significant amount of credits … our concern is the same it’s always been,” said NextEra Energy Resources’ Mark Tourangeau, echoing comments by other members waiting on credit payments. “I would urge the board and all the stakeholders to think about equity from the folks who have to pay upgrade costs, the folks who are due credits and the folks who have to go back” and ask for payments.
“It’s fair to say that when we signed service agreements, there was no indication the charges would be as high as what they are. The fact [that] the payment plan was recently extended shows the board didn’t know either,” said Stuart Solomon, COO of American Electric Power’s Public Service Company of Oklahoma. “So as we were making decisions to enter power purchase agreements, we weren’t making informed decisions. Every indication we had at that time was the costs wouldn’t be at this level, as we were signing service agreements that didn’t reflect all of these creditable upgrades.”
“I feel like the red flag on the rope in a tug of war,” SPP Director Bruce Scherr said. “There are compelling arguments on both sides, but I haven’t moved. It leaves me really uneasy about how to vote.”
“Our primary concern is … what did we know, and when did we know it?” said Les Evans of Kansas Electric Power Cooperative. “Frankly, going forward, I have concerns about how to do business with SPP as a customer. I signed a contract saying I have no direct assigned costs. Four years later, I have a bill for $6 million.”
SPP staff agreed that customers should not be obligated to pay Z2 costs for resources that were not designated in the agreements before service began. Staff also said that sponsored upgrade costs should be allocated based on rules in effect at the time a credit payment obligation is assigned, rather than the rules in effect when an upgrade became creditable.
Staff is working to provide historical billing results for stakeholder review before the October MOPC meeting. The first invoices are scheduled to go out in early November.
Edison International is maneuvering to capitalize on California’s effort to meet its greenhouse gas emissions goals and encourage the use of distributed energy resources.
The 2018-2019 rate case for subsidiary Southern California Edison will include a capital spending request “designed to help California achieve its low-carbon policy objectives and to enable customer choice,” Edison CEO Ted Craver said during a call with investors last week.
Edison’s second-quarter profits fell 27% to $276 million, in part because year-ago earnings reflected a $100 million income tax benefit.
The second quarter of 2015 also included revenue SCE later refunded to ratepayers after a delayed ruling from state regulators on its 2015 rate case.
As a result, the company said, any comparison between the two quarters was “not meaningful.”
Craver said SCE’s rate base is projected to grow 7% over 2016-2017 based on capital spending approved by the California Public Utilities Commission and expected spending on FERC-jurisdictional transmission projects.
While the company expects “relatively little variance” in the timing of its spending on CPUC-jurisdictional projects, it could experience some “variability” in the timing for its FERC projects, which Craver attributed to delays in routing decisions and state and federal permitting approvals.
“A recent example was the $1.1 billion West of Devers project, which has been something of a moving target with CPUC staff — even with CAISO support — but appears ready for final CPUC approval with a supportive alternate proposed decision pending,” Craver said.
Project delays could defer some spending planned for 2017 to subsequent years, he said, but SCE does expect to complete major transmission projects linking the utility’s service territory with renewable generation located farther inland.
Edison anticipates a future shaped by 2015 legislation that seeks to use the grid to help meet the state’s carbon reductions goals, including reducing vehicle emissions through electrification of the fleet. One byproduct of that law is a current CPUC proceeding that seeks to direct utility investment to facilitate the wider adoption of DER.
In response, capital expenditures will be “lumped into two buckets” in the rate case SCE intends to file with the CPUC on Sept. 1.
The first bucket will consist of “traditional” investments, such as replacing aging infrastructure, adding new customer connections, upgrading information technology and maintaining SCE’s generators. The second will reflect investments in the modernization of the utility’s distribution system to facilitate the growth of DER.
Craver said the CPUC has “provided only some early direction on preferred technologies and required investments” for modernization.
Through its upcoming rate case, SCE will be the first utility “to provide specificity for how this technology evolution should unfold,” Craver said.
While Craver said he wouldn’t divulge details ahead of the filing, he noted that some of the utility’s modernization investments amounted to reinforcing the existing system, such as upgrading low-voltage circuits to accommodate increasing amounts of DER.
“But other parts really have no precedent, and therefore we do not know how to handicap how much of our request might finally be approved,” Craver said.
NEW YORK — Speakers at Infocast’s 2nd NY Energy REVolution Summit last week pondered how New York’s Reforming the Energy Vision could deliver on its promise of cleaner and more distributed generation, with persistent low power prices.
The challenge is introducing transformative changes in an environment of already record-low prices, changes that would reduce margins for market participants while also requiring massive investments.
“The state of New York has embarked on two significant transformative issues simultaneously: the Clean Energy Standard driving toward 50% renewables [by 2030] and REV,” Michael Schwartz, CEO of advisory firm New Wave Energy Capital Partners, said during a panel discussion on the latest developments of REV. “If I have seen in the past the potential for stranded investment, this is it. If we’re going to achieve the CES, the state is going to [need to] create incentives for market signals to drive the construction of utility-scale renewables at the same time we’re driving down demand and moving [generation] behind the meter.”
Schwartz said regulators will somehow need to reconcile the initiatives.
“The fundamental change to move from cost-of-service to market-based [utility earnings] is conflicted with maintaining the financial integrity of electric utilities,” he said.
Utilities, while understanding the imperative to revamp their generation fleets, maintain infrastructure and preserve their financial viability, are wary, he added.
“Based on discussions I’ve had, the consensus in other jurisdictions is ‘we’re not doing that,’” Schwartz said.
New York is moving ahead on another legally uncertain path to create financial incentives for its struggling nuclear fleet until large-scale renewables are built to take their place. On Monday, the New York Public Service Commission approved a zero-emission credit for nuclear plants, at a projected cost of $7.6 billion over 12 years. (See related story, New York Adopts Clean Energy Standard, Nuclear Subsidy.)
A proposal earlier this year based the ZEC subsidy on the difference between the cost-of-service from the nuclear plants and the wholesale power prices in NYISO. A PSC staff proposal in July changed the formula to align with EPA’s calculation of the social cost of carbon. Generation owners, customers and some environmentalists object.
David Appelbaum, an attorney for the New York Power Authority, said the change was the result of the U.S. Supreme Court’s April decision in Hughes v. Talen, in which the court voided Maryland’s attempt to incent generation by using a contract for differences related to the PJM capacity market. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
“The order has changed significantly. Before the change, it would have been open to challenge in the context of the [Hughes] decision,” Appelbaum said. “It’s less so, but there’s still risk.”
Whatever the eventual outcome, New York has gotten ahead of many places as it embarks on REV.
“Once you start looking at the regulatory paradigm, regulation was not intended to support this vision. Regulation is still cost-of-service-based,” said Paul DeCotis, a senior director at West Monroe Partners and panel moderator.
However, Jim Gallagher, executive director of the New York State Smart Grid Consortium, said the model is still relevant for now.
“We need to remember that utility cost-of-service regulation is still going to provide 96% of utility revenues for the foreseeable future and these initiatives are going to provide less than 4%,” he concluded.
The developers said they needed an extension while they appeal the denial by New York environmental officials of a required water quality permit under Section 401 of the federal Clean Water Act. (See 
Waste Control Specialists began supplying the Nuclear Regulatory Commission more information about the company’s plans to store high-level nuclear waste in Andrews County, Texas, after a letter from the commission fueled opponent groups’ criticisms.
The Standing Rock Sioux Tribe of North Dakota and South Dakota is suing the U.S. Army Corps of Engineers for issuing permits for a crude oil pipeline it says threatens sacred sites and its drinking water supply.
A number of industry executives called on the Nuclear Regulatory Commission to improve the efficiency of its review processes, especially when it comes to approving advanced reactors.
