CARMEL, Ind. — In what marked a first for the grid operator, MISO last week detailed its spring readiness and said there’s a small possibility of emergency conditions.
While the RTO expects to have adequate resources on hand to meet sometimes volatile demand, it might also have to rely on emergency operating procedures during what was once considered a calm shoulder period, stakeholders learned during a March 8 Market Subcommittee meeting.
“Projected spring transmission and generation outages show challenging but manageable outages, similar to recent years,” said Jeanna Furnish, MISO manager of resource planning and transmission studies.
MISO’s analysis shows a 25% probability it will need to invoke systemwide emergency operating procedures during the spring, but only if either loads or forced outages are higher than normal, Furnish said.
“My presence here isn’t to cause any alarm but to talk about … the realities of challenges that may exist on the system,” Furnish said.
Based on forecasts from the National Oceanic and Atmospheric Administration, the RTO is expecting a warmer-than-usual spring for MISO South and normal to above-normal precipitation in most of its footprint.
MISO said volatile spring loads that deviate from forecasts will require careful coordination of outages.
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Furnish pointed out that MISO maintains a nonpublic member webpage called “Maintenance Margin” that keeps a monthly forward account of how many megawatts can be taken out of service without affecting reliability. The RTO uses the data to inform generators when it predicts outages will have an impact on reliability and will recommend alternative outage schedules.
Last year, high generation and transmission outages paired with unseasonably elevated loads in MISO South produced an early April maximum generation event, unusual for a shoulder season, prompting the RTO to call on load-modifying resources for the first time in a decade. The event prompted the Independent Market Monitor to call for MISO to have increased authority over approving maintenance outages. (See 4 LMRs Face Penalties after MISO Max Gen Emergency.)
Customized Energy Solutions’ Ted Kuhn asked if Maintenance Margin provided any indication that emergency conditions were imminent last spring.
“Was the Maintenance Margin showing a deficit, or did we just fall into a black hole?” Kuhn asked.
Furnish didn’t know but said MISO continues to work with stakeholders to enhance outage coordination, including developing reserves that can be available within 30 minutes and improving congestion management with PJM at the seams by swapping control of flowgates.
MISO did not venture a guess about the projected spring peak. The RTO is planning for a 126-GW summer peak load, which it predicts will require a 17.1% planning reserve margin. (See MISO Planning Reserve Margin Climbs to 17% for 2018/19.)
WASHINGTON — Growing the electric vehicle market beyond early adopters will require creative regulations, an expanded charging network and a vastly improved customer experience, speakers told the Institute for Electric Innovation’s (IEI) spring 2018 forum Wednesday.
“The early adopters were able to deal with some of the challenges of interacting with five different charging networks and the fact that sometimes stations didn’t work; maybe they’re in the back of a parking lot that wasn’t well lit and it was kind of dangerous,” said Scott Fisher, vice president of market development for Greenlots, which sells EV charging software and services.
Fisher said he senses increased momentum for EVs, with moves in Europe to ban diesel vehicles and Volvo announcing all its models will be electric-powered by 2019.
“There seems to be a commitment among large credible companies to create this positive customer experience. So, it’s not going to cater to the 1% anymore. … To get to that 5% or 10% — that next stage of early adopters — thinking about the customer experience that’s needed” is crucial, he said. “Some of it’s in place, but making it more consistent is a really important objective.”
Alan M. Oshima, CEO of Hawaiian Electric and the owner of a plug-in Ford Fusion, agreed. “The [conflicting] charging protocols we have right now is even worse than Betamax vs. VHS,” said Oshima, who moderated the panel discussion.
“It can’t be depending on niches. It can’t just work in California or Massachusetts or New York,” said Mark S. Lantrip, CEO of Southern Company Services. “Somehow we’ve got to think about how we bring everyone along. Until that, it’s going to be a series of fits and starts.”
Exhibit A is Georgia, which — thanks to a $5,000 state tax credit — was the fastest-growing EV market in the U.S. between 2010 and 2014, according to the Edison Electric Institute, which funds the Edison Foundation and IEI. When the tax credit expired, EV sales in the state plummeted. (The federal government continues to offer a $7,500 tax credit.) Still, with 25,500 EVs as of 2016, the state ranked second to California in EV sales between 2011 and 2016.
Wooing Newcomers
Although U.S. EV sales increased by 26% last year to almost 200,000, they still represented only 1% of new vehicle sales. Globally, EV sales jumped by more than 60% last year, with China responsible for more than half the sales in the third quarter.
Fisher said the best marketing EVs could get is more charging stations. “Whenever I talk to my liberal friends in Princeton, N.J., where I live, [they say] ‘Oh, that’s a great car, but where would I charge it?’ If I have to explain to them, I’ve already kind of lost them.”
Lisa Wood, IEI’s executive director, said EVs also will benefit from the increasing visibility of electric fleets such as city buses, United Parcel Service delivery vans and school buses that can provide energy storage in summer. Electric companies have increased their EV fleets by more than 40% since 2015, according to EEI, with more than 70 companies investing more than $120 million last year alone.
Lantrip said proponents are discouraging potential adoptees from making the switch with talk of EVs’ potential as distributed energy storage.
“We’re trying to get people to just even entertain the idea of buying [an electric] car, and what I see in so many presentations on electric vehicles is they immediately go to vehicle-to-grid, vehicle-to-home, and that freaks out the average new potential buyer … because they just don’t get it or want it. It’s like, ‘You’re going to drain my battery?’ We have to separate those two conversations.”
Lantrip predicts EV penetration will not surge until there is price parity between EVs and conventional vehicles and charging times are reduced to five minutes. “We have to manage our expectations,” he said, warning that current investments in the technology and charging infrastructure should be limited to “no regrets” steps while the market remains small and different technologies are competing for dominance.
About 80% of EV charging is done at home, where residents can use either a Level 1 charger (a standard AC outlet providing up to 1.5 kW of electricity that takes 30 hours to fully charge a 115-mile battery) or a Level 2 (a 240-V AC outlet delivering up to 9 kW, which can charge in 5.5 hours). Commercial charging locations with DC-powered fast chargers deliver 50 kW and reduce a 90-mile charge to 30 minutes. In Europe, a new generation of chargers is being installed offering 350 kW, which would complete a charge in 10 to 15 minutes, but no vehicles currently offered can use them.
Norm Saari, a member of the Michigan Public Service Commission, shared Lantrip’s concern about investing in technology that could be rendered obsolete.
Saari said policymakers could be hesitant to act because of uncertainty over what is the “proven, right technology.”
“[Do] you want to have a Level 1 or Level 2 or DC fast charging? Or do you want inductive charging on the road? Or let’s forget about that. Let’s go to hydrogen fuel cells instead. There’s a lot of issues that still have to be resolved,” Saari said.
The Michigan commission held its second technical conference on EVs in February. Saari said he and his colleagues are concentrating on four primary areas: customer education, rate design, the impact of EVs on the grid and charging infrastructure — “who is going to build what, where and how is it going to be priced out?”
Under the “make ready” model, the utility supplies the service connection and supply infrastructure, with the customer supplying the charging equipment. Another model would have the utilities assume full ownership of the charging equipment — the opposite of the business-as-usual model in which the customer is responsible for all equipment.
Saari said he expects both DTE Energy and Consumers Energy to request money for EVs in rate cases the companies will file later this year.
Lantrip said Southern Co.’s Georgia Power will propose several pilot projects to regulators later this year on getting EVs to low-income customers. “It could run the gamut from something like Zipcars or it could be electrified Ubers targeted in certain areas or something in between that,” he said.
Lantrip called on utilities and regulators to be “creative in developing new rate designs.”
Fisher said that although higher EV penetration will mean more electric demand, the grid investments required to expand the market are “going to turn out to be a wise ratepayer investment.”
In California, which has more than 277,000 EVs — about half of the nation’s total — a joint study by the state’s three investor-owned utilities reported the costs of distribution upgrades to serve EVs have been “immaterial.” But Southern California Edison has said 25% of its network must be upgraded to support new chargers.
Dan Adler, vice president of policy for the Energy Foundation, which promotes energy efficient buildings and appliances, said the industry needs “durable” coalitions to ensure regulatory policy does not become an obstacle to growth. “You get better policy outcomes … if the coalition is formed ahead of time,” he said.
Role for Gas Stations
From the audience, D.C. Public Service Commission Chair Betty Ann Kane asked whether the industry was working with gas stations that might otherwise become “stranded investments” in an electrified transportation system.
“If you get the charging times down, there’s an opportunity to work with that community,” Adler said. Because gas stations make most of their profits from snack and beverage sales and not fuel, Adler said, station owners may welcome a new way to generate foot traffic.
Lantrip said new gas stations are increasingly being designed to be fit with electric charging. He said they may be the best locations for charging in urban areas where few residents own garages. Last October, Royal Dutch Shell announced it was buying one of Europe’s largest EV charging providers; it is also beginning to add EV chargers at its stations in the U.K. and the Netherlands.
AUSTIN, Texas — Texas Public Utility Commissioner Brandy Marty Marquez quietly resigned Thursday, saying she will pursue life in the private sector after two decades of public service.
Her resignation is effective April 2.
The announcement came several hours after the PUC’s open meeting. There was little hint of what was to come during the meeting, other than when Chairman DeAnn Walker, a close friend of Marquez, choked up in announcing the commission was going into a closed session to “deliberate personnel matters.” Walker avoided looking at Marquez as she gathered her composure.
“Is that it? Can we go?” Marquez said, smiling broadly. She had already met separately with Walker and fellow Commissioner Arthur D’Andrea before the open session to tell them of her decision.
Marquez’s resignation will mean the three-person PUC has completely turned over since last May, when longtime Chair Donna Nelson left. Her departure was followed by that of Ken Anderson, who resigned after his term expired in August. They were the two longest serving commissioners in PUC history, each having served eight years or more.
Marquez was appointed to the commission in August 2013 by then-Gov. Rick Perry and reappointed by Gov. Greg Abbott in 2015. Her term was to expire in September 2019.
She said in a statement she leaves the commission knowing it will continue to serve Texas “with fairness under the principled leadership” of Walker and D’Andrea.
“Supported by the best staff of any Texas agency, the PUC will continue working tirelessly on behalf of stakeholders and consumers,” Marquez said. “I am honored to have served my fellow Texans. I leave with a happy heart.”
Despite speculation that she would return to the political arena, Marquez said she plans to enter the private sector. She served as Perry’s policy director during his successful 2010 gubernatorial campaign and was his chief of staff during Texas’ 83rd legislative session. The Legislature next meets in January 2019.
“The state of Texas has benefited greatly from the more than 17 years of dedicated service from Brandy Marquez,” Abbott said. “Her commitment and passion for public service have been on full display throughout her impressive career. I commend Brandy for her extraordinary accomplishments during her tenure as commissioner.”
While at the commission, Marquez also served on the Texas Reliability Entity, which serves as the PUC’s reliability monitor for the ERCOT region and enforces NERC standards.
Commission Directs ERCOT to Revise ORDC
The PUC directed ERCOT to begin the process of removing reliability unit commitment (RUC) capacity from the ISO’s operating reserve demand curve (ORDC), which creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves (Project No. 47199).
Marquez said her preference was to wait until after the summer, when operating reserves are expected to be tight, but she joined with Walker and D’Andrea in the decision.
“I think taking out the RUC is the right thing to do,” Walker said. “I don’t think it’s going to make a significant difference for the summer, but it sends the signal we’re fully supportive of the energy-only market, and we will stand behind it.
“I want to be clear that this decision is based on what I believe is the correct decision, and not because anyone has made me believe this,” she continued. “I’ve been there a long time, and I didn’t need help getting there.”
“I can’t envision anybody … who believes in this market that wouldn’t support this change,” Marquez said. “We’ve never gone into a summer like this. It will be an incredible learning opportunity for our market. Anything we’re preparing for now will potentially look very different after August.”
PUC staff have also recommended removing the RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics. Some market participants have pushed back, sharing Marquez’s view that it would be best to wait until after the summer to make the change. (See “Participants Caution Against Market Changes Before Summer,” Overheard at the Infocast ERCOT Market Summit.)
ERCOT staff filed a report with the PUC on March 2 that indicates removing RUC capacity from the ORDC would have provided generators an additional $6.6 million and $18.6 million in revenue in 2016 and 2017, respectively. Given that total generator revenues in ERCOT were about $8.4 billion in 2016 and $9.5 billion in 2017, the adders respectively represented about 0.07% and 0.2% of total revenue, staff said.
The ISO study estimated it would cost $15,000 to $25,000 to modify ERCOT’s systems to remove online RUC and RMR resources from the ORDC capacity value, and could be done internally within 60 days.
ERCOT will include the revised protocol language for its April 10 Board of Directors meeting.
PUC to Intervene at FERC in MISO’s Docket
Following the PUC’s executive session, Walker announced the commission would be intervening in MISO’s application before FERC to create targeted market efficiency projects, a new category of small interregional transmission projects (ER18-867).
Walker also said Thomas Gleeson, the commission’s director of finance and administration, will serve as its interim executive director until a full-time replacement can be found. Brian Lloyd resigned from the position March 1, after seven years. (See Texas PUC Executive Director to Resign.)
LOS ANGELES — Despite recent developments favoring more organized energy markets, Westerners still hold some “anxiety” and “hesitancy” about a new RTO in the region, says Doug Howe, chairman of the Western Energy Imbalance Market’s (EIM) Governing Body.
Howe, a doctor of mathematics, independent consultant, former utility executive and former New Mexico regulator, joined the body when it was established in 2016.
At an EIM meeting in Los Angeles last week, RTO Insider asked Howe how he sees the Western landscape taking shape, and what his concerns are about a possible new Western RTO.
“My sense is still that there is a lot of hesitancy towards a full RTO,” Howe said. “The idea of transmission allocation and a uniform transmission price across a region as big as the Western Interconnection gets a lot of people a little nervous, because we have widely varying transmission costs in the West.”
Several possible changes are stirring the West, including a joint proposal by Peak Reliability and PJM to create a new market and CAISO’s plan to extend its day-ahead market across the EIM. (See Calif. Lawmakers Relaunch CAISO Regionalization.)
While the Peak/PJM market proposal only sets out to establish an energy market, and not a full RTO, Peak executives have described it as a “pathway” to an RTO.
“All of these initiatives are in some sense a pathway to an RTO,” Howe said. The question is how to deliver the benefits of an RTO, such as day-ahead, real-time and ancillary services markets, “without triggering all this anxiety,” he said.
The best approach, according to Howe?
“Let’s get the energy markets established first and then we will see where stakeholders are comfortable going.”
Howe said industry participants have several choices to examine now and will be analyzing the costs and benefits of each one, “and whether it has sufficient bells and whistles — is it the right market to be in?”
One concern is “the absence of a real exit strategy” if a market participant joins an RTO, he said.
“If you find it’s not working out for you, getting out is extraordinarily expensive,” Howe said. While CAISO is seeking to extend the day-ahead market across the EIM, an RTO “is not what we are proposing at this point.” The trade-off is that participants don’t get the full benefits of an RTO either, he said.
When asked about whether there is unease about a balkanized and noncontiguous market taking shape, Howe said, “I don’t think there is a lot of concern about that.” The Eastern U.S. is balkanized to some degree and “it’s a spider web of transmission,” he said. In the West, transmission lines run north and south and east and west from the coast inland.
“They have worked that out in the East, but there is some concern that the West is not the same as the East, and that is going to be part of the working-out process,” Howe said. “There might be a little more concern about the reliability coordinator becoming balkanized, because they are the ones that have a high-level view of the entire grid.”
LOS ANGELES — Western Energy Imbalance Market (EIM) leaders last week endorsed CAISO’s controversial proposal to give generators more bidding flexibility, but not without giving ground to the plan’s skeptics.
The EIM’s Governing Body on Thursday approved the ISO’s Commitment Costs and Default Energy Bid Enhancements (CCDEBE), designed to give generators more latitude in how they reflect their commitment — or start-up and minimum load — costs and overhaul the way the ISO calculates the default energy bid, which replaces bids of units found to have market power.
The current method can artificially limit a generator’s commitment cost and limits what the generator can bid in, the ISO has said.
But to the end, market participants and the ISO’s Department of Market Monitoring raised questions after a lengthy stakeholder process to develop the rules. (See CAISO Developing New Bidding Rules.)
The rule changes still require approval by the CAISO Board of Governors, which will consider the proposal at its March 21-22 meeting.
‘A Good Place’
CAISO’s proposal replaces a static commitment cost bid cap with a local market power mitigation test, which identifies whether a resource needs to be committed to relieve a transmission overload or other constraints, the same way energy bids are handled. The ISO will only mitigate bids when a generator fails the test.
Under the current rules, the ISO calculates reference levels for each gas-fired generator based on published natural gas price indices. The commitment cost reference level is determined by multiplying costs by 125% and bids are capped at the generator’s reference level.
CAISO plans to phase in commitment cost bidding flexibility, first raising the commitment cost multiplier to 150% for the first 18 months after implementation, and then increasing it to 300% if no issues arise.
During the rulemaking process and at Thursday’s meeting, there was heavy debate over CAISO’s plan to automatically increase the reference levels after 18 months. Some commenters, such as Governing Body member Kristine Schmidt, suggested that a new stakeholder process might be needed at the 18-month point.
But CAISO Vice President of Market and Infrastructure Development Keith Casey resisted the idea, saying “it sends a message to the market that we are not serious about this.”
Body members compromised by adding a provision to the decision that the ISO provide a status report to the EIM and CAISO board at the 18-month point.
“This was tough one, but I think we ended up in a good place on this,” Governing Body Chairman Douglas Howe said.
The ISO recently lowered the proposed multiplier for the first 18 months to 150% from 200%, in an “abundance of caution,” Market Design Manager Brad Cooper said, calling the bid cap a “circuit breaker.” The proposal also allows suppliers to seek adjustments to their reference levels based on changes in documented costs.
“We believe that we have a robust design, but we agree we need to proceed cautiously with changes,” Cooper said during a presentation to the Governing Body.
Respectful Disagreement
DMM Director Eric Hildebrandt supported the proposal, saying “the basic framework is there.” But he recommended a few changes, saying there are some gaps, a potential for economic withholding and for a “kind of gaming.” (See Monitor Critical of CAISO Commitment Cost Mitigation Plan.)
“We have looked at it, and we respectfully disagree,” Casey responded, adding that some power suppliers are “sort of biting their tongue” on the arrangement for the first 18 months. An automatic change at the 18-month point provides certainty that the ISO is committed to moving to the higher cap, he said, adding that CAISO can always file with FERC to keep the level at 150% if it discovers issues.
Howe said the EIM’s decision “is trying to carve a middle road,” but he didn’t think CAISO should “back into” a second stakeholder process that would “allow everybody to have a second bite” at things they didn’t like.
Body member John Prescott said, “I support this, and I would advise the Board of Governors to support this as well.” He said he expects the DMM to make sure issues don’t materialize.
Representing the Western Power Trading Forum, Carrie Bentley of Resoro Consulting told RTO Insider that the parties most affected by the change will be EIM entities or others who have experienced challenges with CAISO calculating their proxy costs, and generators and scheduling coordinators impacted by high gas prices.
She said that while WPTF supports the proposal, she called CAISO’s changing the reference level late in the proceeding “an unfortunate circumstance of panic policymaking in response to a few influential stakeholders. The CAISO had an excellent proposal, and it would have been better if they just remained confident in it.”
CARMEL, Ind. — MISO’s Independent Market Monitor is backing the RTO’s proposal to revise its uninstructed deviation rules to allow generators to recoup a portion of make-whole payments even when their ramp rates fall short of expectations.
Monitor David Patton said last week that he now favors the “less draconian” performance-based proposal over his original recommendation from last year’s State of the Market report.
MISO’s plan would calculate a generator’s uninstructed deviation by comparing the time-weighted average of its real-time ramp rate with its day-ahead offered ramp rate, while allowing for a 12% tolerance from set point instructions. The proposal eliminates the RTO’s current “all or nothing” eligibility for make-whole payments, instead allowing generators to collect full payments when they respond to dispatch instructions at a rate of 80% or higher over an hour, while excluding payouts when performance rates fall below 20%. Units operating between those two thresholds would earn make-whole payments in proportion to performance.
The RTO currently flags generators that deviate from ramp rate dispatch instructions by more than 8% over four consecutive five-minute intervals, putting them at risk of losing day-ahead margin assurance payments (DAMAPs). The new approach would eliminate all current ramp rate requirements except for the one requiring rates of greater than 0.5 MW/minute.
Patton said MISO’s time-weighted approach provides generators greater incentive to follow their offered ramp rates than his earlier proposal requiring units to move at least half their offered ramp rate within a 20-minute grace period before being flagged and losing make-whole payments. (See MISO Tempers Dispatch Plan After Stakeholder Pushback.)
“That 15 minutes is a knife edge,” Patton said of the originally proposed 20-minute grace period before becoming ineligible for DAMAPs. “Generators motionless after 15 minutes will have to move at 100% of their ramp rate immediately to avoid exceeding 20 minutes.”
He also pointed to the benefits of performance-based partial payments.
“Over the course of an hour, generators will have a stronger incentive to perform better. If you perform reasonably well, you’ll make more money than if you don’t perform reasonably well,” he said.
Patton said MISO generators have so far been discouraged from providing a “multi-point” ramp rate that factors the time it takes to move a unit in the first few moments after firing it up. He said using an average of hourly performance will allow for nuances.
Some stakeholders agreed that it was a good idea to allow a lagging lead-time for slow-moving units but said the proposal doesn’t help wind and solar generators, which have a tendency to be flagged for excessive energy production.
Patton acknowledged that wind power may need a “special rule,” saying MISO could make “simple” changes to excessive energy flags for wind only when the excessive ramping doesn’t cause congestion.
MISO plans to continue refining the uninstructed deviation proposal through April.
While structural issues persist, PJM’s markets were competitive in 2017, the RTO’s Independent Market Monitor said Thursday, contradicting concerns from PJM and some stakeholders that prices are unsustainably low.
In his annual State of the Market Report, Monitor Joe Bowring noted that PJM’s energy, capacity, regulation, synchronized reserve, day-ahead reserve and financial transmission rights markets all produced competitive results with competitive participant behavior, although all showed either market structure or design issues. Bowring recommended improvements for each market.
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But the results show that the generation fleet remains relatively diverse and that most plants are receiving enough revenue to be profitable. All diesel and pumped-storage resources, and nearly all gas-fired combustion turbines and hydro stations, received full recovery of their avoidable costs, as did 88% of oil- or gas-fired steam units and 86% of gas-fired combined cycle plants.
Among nuclear plants, 68% earned enough revenue to cover an industry-standard calculation of costs developed by the Nuclear Energy Institute.
Using capacity auction results going forward, the report found only four nuclear facilities are threatened with negative revenues: Oyster Creek (which is already slated for decommissioning), Davis-Besse, Three Mile Island (TMI) and Perry. Quad Cities and Byron, the beneficiaries of Illinois’ controversial zero-emissions credits legislation, had been unprofitable four of the past five years but are projected to turn a profit through 2020.
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The Salem nuclear plant also is expected to remain profitable through 2020. Asked why Exelon and Public Service Enterprise Group, which jointly own the two-unit facility in southern New Jersey, decided to halt capital expenditures at the plant, Bowring said he was “not quite sure” the reasoning.
“Based on publicly available data, it is more than covering its costs,” he said. “Nuclear units are not making a lot of money, but generally … they are not receiving a retirement signal from the market.”
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“It’s not surprising” that single-unit facilities are the ones that are getting that signal, Bowring said. Additionally, he argued that NEI’s number was “inappropriate” because it included additional costs that were incurred in the aftermath of the Fukushima disaster in 2011. Using two-thirds of those costs, all but TMI and Davis-Besse will be profitable.
Just 52% of coal-fired plants recovered their avoidable costs, the report showed. PJM’s plan to revise price formation would support large, inflexible units like coal plants, but Bowring said the reforms were not based on market flaws. Nearly 79% of the $24.7 million uplift costs from day-ahead operating reserve differences were paid to coal units in 2017, but not because of market design issues, he said.
“That actually has to do with some very specific circumstances about coal units that have nothing to do with convexity and non-convexity and would not be affected by PJM’s price-formation proposal,” Bowring said.
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Coal units also received nearly 85% of $20.4 million in uplift paid for reactive services, but gas turbines gobbled up the vast majority of the remaining $83 million uplift payments for lost opportunity cost, black-start services, local constraints control and balancing operating reserves.
While new combined cycle facilities could turn a profit in some zones, the revenue available in 2017 didn’t cover the cost of entry for new combustion turbine generators, nuclear or other units.
“The PJM system is significantly long” on generation, Bowring said, in part because the RTO has been regularly over-forecasting demand. The average real-time demand was down 2.2% from 2016 to 86,618 MWh. Peak and average load were also down.
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That factored into a $30.99 average LMP, which was up 6% from 2016 but lower than every other year since 2000. Much of that came from coal and gas prices, which combined to account for nearly 70% of the LMP.
AUSTIN, Texas — Texas regulators quickly dispensed with two multiyear cases before them Thursday, clearing the way for Sempra Energy to acquire Oncor and for Lubbock Power & Light to migrate from SPP to ERCOT.
The Public Utility Commission made only minor revisions to the Sempra-Oncor order and added several tweaks to the LP&L order, spending more time during its open meeting congratulating those involved in the two proceedings.
PUC Chair DeAnn Walker recalled attending the National Association of Regulatory Utility Commissioners winter meetings, where she heard a financial analyst say, “What’s best for us is when a utility commission speaks, they stick to what they have asked.”
“This commission and the intervenors spoke at least twice, maybe three times in the preliminary order, on what their expectations were to get things done,” Walker said, referring to the Sempra-Oncor settlement agreement with all intervenors in its application (Docket No. 47675). “Sempra listened to that and came forward and did that. I think it speaks for y’all and it speaks for the commission that we have now stuck to what we said we were asking for.”
Oncor ‘Saves Best for Last’
The PUC’s approval of Sempra’s acquisition of Energy Future Holdings’ 80.03% interest in Oncor all but seals the California-based company’s pursuit of Texas’ largest electric utility. Sempra has already received approval from FERC and the U.S. Bankruptcy Court for the District of Delaware, where EFH filed for bankruptcy in 2014. (See Bankruptcy Court OKs Sempra-Oncor Deal.)
Sempra has succeeded where others failed. Its $9.45 billion all-cash bid for Oncor caught Warren Buffett’s Berkshire Hathaway Energy off-guard in August, while Hunt Consolidated and NextEra Energy saw their acquisition attempts fall apart before the PUC.
“We clearly saved the best for last with Sempra,” Oncor spokesman Geoff Bailey told RTO Insider outside the PUC’s hearing room. “We’ve got a four-year process behind us, and we’re ready to move forward into the future. I think I speak for all Oncor employees when I say it’s an exciting day for the company. We’re excited to get everything behind us.”
“We appreciate the commission’s support throughout this long, four-year process to find a new majority owner for Oncor,” Oncor CEO Bob Shapard said in a statement. “We believe this is an excellent outcome for our company, our customers and our employees. Sempra Energy is a well-run company, and we believe they will be a strong, stable majority owner for Oncor and an excellent partner for Texas.”
Headquartered in San Diego, Sempra is a Fortune 500 company with 16,000 employees and about 32 million consumers around the world. The company earned more than $11 billion in revenue last year.
Oncor operates the largest distribution and transmission system in Texas, delivering power to more than 3.5 million homes and businesses while operating more than 134,000 miles of lines.
Sempra CEO Debra Reed said she was pleased the commission found the transaction to be in the public interest.
“Sempra Energy is committed to being a good partner for the state and is supportive of Oncor’s mission to provide Texans with safe, reliable and affordable electric service,” she said.
In reaching an agreement with various consumer groups before the PUC, Sempra agreed to employ strict ring-fencing measures that include an independent board of directors, to extinguish EFH’s debt and to pass tax savings on to Oncor customers. (See Sempra, Oncor Reach Agreement with Texas Intervenors.)
Shapard and General Counsel Allen Nye will both retain positions on the post-acquisition board of directors as chairman and CEO, respectively.
“You can’t get your fancy pants on now that you are going to be CEO and think you’re too big for us,” Walker told Nye. “You have to come visit us and see us from time to time. I know you have a company to run, but this is a regulated industry, and guess what we do.”
“I‘ve had the distinct pleasure of being here almost 25 years now, and I have no intention of going away,” Nye responded. “This place means the world to me. You can get used to seeing me.”
Sempra will fund the purchase through of combination of about 65% equity and 35% long-term debt. It said in a letter to the PUC that it intends to acquire Oncor Management Investment’s 0.22% interest in Oncor when or after the transaction closes.
Should Sempra pursue the remaining 19.75% interest in Oncor held by Texas Transmission Investment, it would need to secure the commission’s approval and adhere to the same regulatory commitments to which it has already agreed.
Sempra said that the transaction “remains subject to certain customary closing conditions” and that it expects to wrap it up “shortly.”
Bailey promised that Oncor’s customers “will see no changes and not be impacted by this transaction.”
LP&L Welcomed into ERCOT
“Welcome to ERCOT, hopefully,” Walker said to Lubbock Mayor Dan Pope after the commission approved a draft order allowing the city’s utility to join the ISO (Docket No. 47576). “It is by far the best ISO/RTO in the United States.”
Speaking to the media minutes later, Pope agreed with Walker as he called it a “big day.”
“In some ways, this is pretty historic,” he said, noting Lubbock is the largest municipality to join ERCOT in almost 25 years. Pope said the key reason the city decided to join the ISO’s open-access market is because “it is the most efficient, competitive energy grid in the country, and it provides the most choice.”
LP&L announced in 2015 that it intended to move about 70% of its load from SPP to ERCOT. The city’s power needs are currently met through two long-term contracts with Southwestern Public Service, one of which expires in June 2021, LP&L’s target date to join ERCOT.
LP&L has agreed to pay $22 million annually over five years to compensate ERCOT’s transmission customers for additional infrastructure costs and to make a one-time $24 million payment to SPS for previous infrastructure costs. (See PUCT Nears Approval on LP&L Move to ERCOT.)
The PUC directed LP&L to work with Sharyland Utilities — which has proposed a $247.5 million, 345-kV project that overlaps with the facilities necessary to integrate Lubbock’s load into ERCOT — to coordinate their responsibility for respective parts of the system. Lubbock must also determine how to extend customer choice to all its customers.
Pope said the city and LP&L are already working on interconnecting with ERCOT and giving all its customers a competitive option. “Ideally, all of our citizens have to have that ability to opt in,” he said.
Speaking for SPP, General Counsel Paul Suskie said the RTO recognizes that membership and participation is voluntary.
“Entities have the ability to make decisions they believe are best for their organization and their customers, which Lubbock has done in this situation,” Suskie said.
Portland General Electric (PGE) and the Bonneville Power Administration said Wednesday they have signed two agreements that will help PGE avert a generation shortage after it shuts down its coal-fired Boardman Generating Station in 2020.
PGE in 2010 agreed to close the 550-MW Boardman plant to avoid investing the $470 million in pollution controls needed to keep Oregon’s last coal-fired generator running until its original 2040 retirement date. The utility last year halted efforts to build two new gas-fired plants at the Boardman site, saying it was instead pursuing talks to obtain existing resources.
Wednesday’s announcement revealed those resources will be supplied by BPA, which will sell the Oregon utility up to 200 MW of surplus hydropower from the Federal Columbia River Power System under two concurrent five-year power purchase agreements for two different energy products, starting in January 2021. BPA told RTO Insider it could divulge only limited details about the contracts because they are subject to a non-disclosure agreement.
“That said, we can say that the two products are an advance notice right to power, each with different notification timeframes,” BPA spokesman David Wilson said. “Each product also carries asset-controlling supplier status,” which allows the associated energy to be exported to California with a low emissions factor for the purpose of greenhouse gas reporting under that state’s cap-and-trade program.
BPA said there were benefits to both parties in the deal, with PGE gaining access to fast-ramping resources while the federal power marketing agency pursues one plank of its recently announced strategic plan, which includes the marketing of “competitive products and services.”
“In addition to allowing BPA to take advantage of a new opportunity to market its clean, flexible hydropower and generate direct revenue as part of a broadening portfolio of power products, the contracts allow PGE more time for new dispatchable resource technologies to mature to help the company integrate increasing amounts of renewable power onto its system,” BPA said.
“These agreements are a great opportunity for us to collaborate with BPA to achieve shared goals in the region,” said PGE CEO Maria Pope.
The deal also has found support among key ratepayer and environmental advocates in the region.
“This is a great deal for the region. It’s a value-added product for the federal power system and a good alternative for PGE. It puts off big new investments in gas that would have locked PGE and its customers into fossil fuels for decades,” said Bob Jenks, executive director of the Oregon Citizens’ Utility Board.
“Instead of building new carbon-emitting resources, PGE is able to take advantage of existing clean hydropower, and BPA is able to lock in a future sale to help strengthen its financial health,” said Wendy Gerlitz, policy director with the NW Energy Coalition.
The power that PGE acquires under the BPA contracts will not count toward Oregon’s 50%-by-2040 renewable portfolio standard, which bars facilities that began operating before 1995. But it will contribute to the utility’s efforts to meet an Oregon requirement to reduce emissions to 80% below 1990 levels by 2050.
PGE earlier this month circulated a draft request for proposals seeking 100 MW of renewable power to help meet both those mandates. The utility expects to bring those resources into its portfolio by 2021.
The utility last October joined Western Energy Imbalance Market (EIM), drawing $2.8 million in net benefits during its first three months of participation, according to CAISO.
FERC on Tuesday rejected separate complaints by the Nebraska Public Power District and Xcel Energy over billed charges under Attachment Z2 of SPP’s Tariff.
Filing on behalf of its Southwestern Public Service affiliate, Xcel alleged SPP’s assignment of $12.8 million in credit payment obligations under Z2 and $485,000 in zonal charges violated service agreements with SPS, and that the filed rate doctrine and the RTO’s implementation of Z2 violated the Tariff’s “but for” test (EL18-9).
NPPD complained SPP misinterpreted its Tariff and improperly billed the utility for 86 Z2 revenue credit obligations and said the misinterpretation will subject it to future monthly charges under regionwide and zonal rates eligible for recovery (EL17-86).
Attachment Z2 assigns financial credits and obligations for sponsored transmission upgrades. The RTO last year completed a resettlement of the Z2 revenue, crediting amounts for March 2008 to August 2016, a move made necessary because of corrections and true-ups to the data that were identified before the first settlement of the charges. (See “More Z2 Woes; SPP to Resettle 9 Years of Data,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
SPP’s headquarters in Little Rock, AR | WER Architects
FERC has consistently sided with SPP in member complaints to the commission. It denied requests by several members to rehear FERC’s 2016 order waiving the one-year limit for adjusting Z2 payment obligations and revenue distributions for transmission projects. It also partially granted Kansas Electric Power Cooperative’s complaint in a separate transmission dispute with SPP, denying some claims and setting settlement judge procedures on others. (See FERC Rejects SPP Change on Network Resource Upgrades.)
FERC: Xcel Should Have Been Aware of Z2 Costs
The commission dismissed Xcel’s argument that SPS’ service agreements with SPP resulted from the RTO’s aggregate transmission service study process, were accepted by the commission and should have reflected SPS’ final cost responsibility as part of the filed rate. Xcel asserted that when SPS executed the resulting service agreements with SPP, the agreements should have contained all of the final responsible upgrade costs.
But FERC found the aggregate study reports alerted Xcel to the potential for SPS to be directly assigned costs for upgrades later determined to be necessary to support the transmission service request (TSR) in SPS’ agreements. It noted SPP was developing the Z2 revenue crediting mechanism when it provided Xcel with study reports and, “therefore, could not provide accurate estimates.”
The commission also rejected Xcel’s allegation that SPP’s assignment of costs violated Attachment Z2 and the filed rate doctrine, finding that Xcel misinterpreted the RTO’s application of the “but for” test. FERC found SPP’s methodology to be “reasonable” in determining whether a TSR makes subsequent use of creditable upgrades and that the “but for” test to determine credits under Attachment Z2 was a “reasonable and practical application.”
SPP’s Tariff Interpretation Correct
FERC also found SPP correctly interpreted its Tariff by classifying more than $860,000 in upgrades identified in NPPD’s complaint as service upgrades eligible for base plan funding cost allocation. The commission said the upgrades were initially determined to be necessary for generator interconnection requests, and the costs were directly assigned to customers “consistent” with interconnection procedures and the Tariff’s pro forma interconnection agreement, making them creditable upgrades.
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The directly assigned upgrade costs became eligible to be recovered through revenue credit payments that made “subsequent use of the upgrades,” the commission said. In implementing the Z2 crediting process, SPP identified additional creditable upgrades subsequently used by previously studied TSRs and associated credit payment obligations, FERC said.
The commission said those obligations became eligible for base plan funding under the Tariff’s cost allocation rules and were included in the rolled-in allocation of costs to transmission customers through the regionwide and zonal rates.
“Therefore … these costs were properly allocated under base plan funding,” FERC said, in rejecting NPPD’s assertions that SPP should allocate the costs differently.
