The U.S. Supreme Court announced March 6 it would not hear a challenge seeking to reinstate the federal right of first refusal in transmission construction, letting an appellate ruling sustaining FERC Order 1000 stand.
In April, the 7th U.S. Circuit Court of Appeals in Chicago upheld Order 1000’s removal of the federal ROFR in a challenge by Ameren and other MISO transmission owners (14‐2153). The case was combined with two challenges by LSP Transmission Holdings that contended FERC did not go far enough in injecting competition into transmission development (14‐2533, 15‐1316).
Laying the foundations for Ameren’s Three Rivers Transmission Line | Plocher Construction
Ameren filed a petition for certiorari with the Supreme Court in October. The company, with Northern Indiana Public Service Co. and Otter Tail Power, argued that the April ruling is at odds with the Mobile-Sierra doctrine, and said FERC should assume the ROFR is reasonable unless the commission proves it is contrary to the public interest. The companies warned that failing to reverse the 7th Circuit’s ruling would allow FERC to ignore the Mobile-Sierra presumption in the future.
FERC decided in 2011’s Order 1000 that federal ROFRs that give incumbent transmission owners first pass on new project construction were anti-competitive and should be removed from all FERC-approved tariffs. Order 1000 did not, however, pre-empt state or local ROFRs.
“The Mobile-Sierra doctrine is based on the assumption that sophisticated parties with competing interests and equal bargaining power will usually reach a compromise that is reasonable and fair. The opposite is true when parties collude with one another to restrain competition and maintain a monopoly. … There is no reason to believe that a contract negotiated by parties with a shared interest in excluding third-party competition is similarly just and reasonable,” FERC wrote in a brief to the Supreme Court in February.
MISO still honors state and local rights of first refusal and can use a limited federal ROFR for certain grid reliability projects. The RTO does not have a competitive project scheduled in 2017 because the year’s lone market efficiency project — the $80.9 million Huntley-Wilmarth 345-kV line in Minnesota — is covered by the state’s ROFR. (See MISO Board Approves MTEP 16’s $2.7B in Tx Projects.)
ALBANY, N.Y. — A New York State Assembly hearing Monday to explore the Cuomo administration’s subsidies for upstate nuclear plants left lawmakers frustrated as the Public Service Commission and the New York State Energy Research and Development Authority declined to attend and Exelon sent no senior executive with knowledge of the subsidy negotiations.
“I’m disappointed that they chose not to attend,” said Assemblyman Jeffrey Dinowitz (D-Bronx), the head of the Committee on Corporations, Authorities and Commissions, who chaired the meeting. “It’s important to hear from PSC and the executive branch.”
Exelon, owner of all the nuclear plants set to receive the zero-emissions credits, sent five witnesses, most of them engineers, with the highest rank being a plant vice president. “Maybe you can take notes and send your answers later,” Dinowitz told them sarcastically.
Exelon also submitted testimony from Joe Dominguez, executive vice president of governmental and regulatory affairs and public policy, who said the company would spend $700 million on the plants because of the financial assurance provided by the ZECs. The ZECs would benefit Exelon’s R.E. Ginna, and Nine Mile Units 1 and 2 generators — and the James A. FitzPatrick plant it is purchasing from Entergy — for more than 12 years.
‘Staggering Increase’ in Pollution
“The closure of these plants would have resulted in a staggering increase in air pollution throughout New York because the electricity void created by the closures would have been filled by coal, oil and gas plants operating in and around New York,” Dominguez said.
The PSC said it was unable to attend because of scheduling problems.
“Unlike the 24 public hearings that the Public Service Commission held across the state in developing the Clean Energy Standard [CES], which were scheduled many weeks in advance, the Assembly only informed us of this hearing late last week, and so we were unable to attend due to scheduling conflicts,” PSC spokesman James Denn said in a statement. The Assembly issued the public notice for the hearing on Monday, Feb. 27.
Instead, the state agencies submitted written testimony from PSC Chair Audrey Zibelman, NYSERDA CEO John Rhodes and Richard Kauffman, Cuomo’s top energy adviser. The statement defended ZECs, part of the CES, which also requires that the state generate 50% of its electricity from renewable resources by 2030.
“Fossil fuel generators and anti-nuclear activists have attempted to mischaracterize the Clean Energy Standard as a bailout or a tax,” they wrote. “But … it is unquestionable that the Clean Energy Standard benefits all New Yorkers across the state and, moreover, charts the most responsible path forward on combating climate change and growing our clean energy economy. … Simply put, without the ZEC program, New Yorkers would pay more for dirtier power.”
$7.6 Billion Cost
Several New York City-area legislators have questioned the wisdom and process of last August’s decision by the PSC to approve the CES and ZECs.
The program distributes costs statewide; in its first two years, all New York energy consumers will pay an additional $965 million to keep the nuclear plants running. The costs may rise by as much as 10% in each successive two-year tranche, for a potential total of $7.6 billion.
Dinowitz chaired the hearing in place of Energy Committee Chairwoman Amy Paulin, who was unable to attend. The other committees participating in the hearing were Environmental Conservation, chaired by Assemblyman Steve Englebright (D-Setauket), and Consumer Affairs and Protection, chaired by Assemblyman Brian Kavanagh (D-Manhattan).
Englebright said that he remembered when nuclear power was being touted as being “too cheap to meter, which doesn’t seem to be the case today.” Kavanagh said he was concerned whether the ZEC charges are fairly imposed and in a transparent manner.
Subsidies Too Generous to One Company?
Blair Horner, director of the New York Public Interest Research Group (NYPIRG), testified first and focused on “a public information gap, which seems like a deliberate strategy. A year ago, we were talking about a $100 million bailout of the upstate plants. Then, as soon as the Assembly went into recess, a significantly more expensive program appears. Is this democracy? It’s no surprise the executive branch chooses not to testify.”
Horner said that the state already has 800,000 electricity users who are 60 days or more in arrears on their electric bills and that the CES-related rate hikes would be a hardship for them. The Cuomo administration says the CES, including the ZECs, will add less than $2/month to the average residential customer’s bill.
Exelon expects the New York ZECs and a similar program in Illinois will add 17 cents/share to its 2017 earnings, 6% of its total profits, according to Crain’s Chicago Business.
“We view the CES charges as a tax being imposed by the wrong branch of government,” said Horner. “Even if you disagree with our view, at least the process should be changed to create a meaningful public process. It’s your duty as a co-equal branch of government. The beneficiary of this program is one company, and $7.6 billion seems overly generous to me. Hit the pause button.”
Assemblyman Will Barclay (R-Pulaski) responded that NYPIRG “seems more anti-nuke than pro-public. There were no complaints about zero-emissions credits for renewables.”
Legislature Should Set Energy Policy
Former Assemblyman Richard Brodsky, a longtime opponent of the Indian Point nuclear plant, testified as a private citizen and reminded lawmakers that the PSC was indeed “a legislative agency, not an offshoot of the executive.”
Brodsky urged the Assembly to reconsider the decision to spend an estimated $303,000 per job per year in subsidizing “decrepit” nuclear facilities. “They’re fixer-uppers, and it costs more to do that than to live in a new house,” he said.
The social cost of carbon used by federal agencies to value the climate impacts of rulemakings — and used to set New York’s ZEC values — was not meant as a policymaking tool and has massive limitations, Brodsky said. “I didn’t know the Constitution had a pause button — it’s time for the legislature to set energy policy. The ISO’s market clearing price is the most idiotic policy ever.”
Not ‘Decrepit’
Exelon sent five witnesses to the hearing: Joseph Pacher, site vice president at the Ginna plant; James Vaughn, senior engineering manager at Nine Mile Point; Adam E. King, radiation protection supervisor at FitzPatrick; John Scalzo, engineer; and James Melville, senior radiation safety operator at FitzPatrick.
Pacher said that, far from being decrepit, “all three stations are performing better than when new,” citing their capacity factors of more than 90%. “Preserving nuclear plants upstate is good sense. These plants could be run safely for decades.”
Dinowitz asked about the costs of operating each plant, but none of the witnesses could answer. Vaughn said that the “$7.6 billion is an estimate, and keep in mind that without natural gas prices so depressed, we wouldn’t need any subsidy at all. It’s not to line our pockets but to keep the plants profitable. The ZEC program establishes a floor price, so if gas prices go up we’ll take less in subsidies.”
Englebright said, “ZEC is supposed to be a transition program, not preserve the status quo. When did Exelon first think they would need a subsidy?”
2015, Pacher replied, which was when the company began negotiating a reliability support services agreement at Ginna, which FERC approved in March 2016.
Kavanagh asked if the upstate plants were safer than Indian Point, which is slated to close by 2022 under an agreement between the Cuomo administration and plant owner Entergy. Cuomo has long sought the plant’s closure because of its proximity to New York City. (See related story, NYISO, PSC: No Worries on Replacing Indian Point Capacity.)
“We don’t operate Indian Point, so I don’t want to say,” Pacher responded. “There’s public perception of aging, decrepit nuclear plants upstate, but people who take tours are always impressed with our facilities.”
Kavanagh asked if the Ginna reactor wasn’t the same design as that at the Fukushima Daiichi plant in Japan, which failed when it was flooded by a tsunami in March 2011. Pacher admitted the similar designs but said it was the Japanese plant’s location on the Pacific Ocean that was its biggest vulnerability. “The worst thing for Fukushima was its location, but examining their experience did lead us to re-evaluate our event amelioration strategies,” he said.
Exelon says its nuclear plants, with a total capacity of 3,350 MW, employ 2,600 full-time workers and pay more than $45 million in annual property taxes and $144 million in “direct and secondary state tax revenues.”
In a separate action, a group of energy companies and trade groups in October filed a suit in U.S. District Court for the Southern District of New York, claiming the ZECs intrude on FERC’s jurisdiction over interstate electricity transactions. The suit asks the court to find the ZECs invalid and order the PSC to withdraw them from the CES.
AUSTIN, Texas — When Diego Villarreal looks north across the Rio Grande toward Texas, he sees a deregulated energy market that looks very much like his country’s.
That stands to reason: Mexico has borrowed the best elements of competitive markets from around the globe and learned from U.S. “success stories” — including ERCOT.
In less than four years, Mexico’s electricity sector has been transformed from a state-run monopoly into a burgeoning marketplace where energy, capacity, financial transmission rights and clean-energy certificates are traded in day-ahead, real-time and capacity markets.
Villarreal, the deputy managing director of electric industry coordination for Mexico’s Ministry of Energy, takes understandable pride in the transformation.
“Where we are right now … that basically took Texas about 10 years,” he said during last week’s Infocast ERCOT Market Summit. “We have been working nonstop to get it where it is in only three and a half years. Yes, there are some elements missing, but keep in mind, it’s only been three and a half years.”
Key to the market’s reform, Villarreal told his audience, was the concept that Mexico “is not an isolated island,” but part of a regional market where “integration can lead to lower prices and more generation” — all of which could be quickly disrupted if the Trump administration continues to insist on building a large physical wall, or “larga barrera física,” along the border.
“It goes without saying that integrating with the United States … is, and was, an essential assumption of the reform,” Villarreal said. “But recent political changes have put that into question.”
Mexico already has five DC ties with the U.S. — three across the Texas border and two with California — with a total capacity of 1,086 MW. Another eight interconnections provide an additional 788 MW of capacity of emergency power.
Mexico-US interconnections are in two main regions: Baja California / California and Tamaulipas-Coahuila / Texas. There are 5 interconnections (1086 MW) in permanent operation; and 8 interconnections (788 MW) for emergency backup. | Mexico Ministry of Energy
Mexico’s natural gas market is just as integrated, with more than a dozen pipelines connecting with the U.S.
Noting that he is not part of Mexico’s negotiating team with the U.S., Villarreal told RTO Insider, “The idea is to find a way for both countries to keep on having a positive relationship with respect to energy trade. The underlying assumption is this will still happen.”
But Villarreal also thinks there’s now a “wild card”: Changes to the free-trade agreement between the two countries could result in “strange consequences” — such as a “very onerous” process for permitting gas exports south of the border.
The Comisión Federal de Electricidad (CFE), the government electricity monopoly, has been broken up into seven generating subsidiaries, which bid into the day-ahead market along with several international generators. Those independent producers include Spain’s Iberdrola and Global Power Generation and several new Mexican companies, and could potentially include American generators.
“Some very large [American companies] that you’re very well aware of … will be transacting in the market very soon,” Villarreal promised. He pointed out that LMPs in Mexico are double those in ERCOT, which averaged $24.62/MWh last year, and said a “very healthy price differential” has been driving flow from Texas across DC ties that are “half-used” during summer’s high demand.
Mexico’s forecasted load growth can serve as a buffer for ERCOT’s oversupply and aggressive wind program, Villarreal noted.
“It’s money lying on the floor,” he said. “Someone has to pick it up. It’s going to go away as people come into the market.”
Gas trade between the two countries is much more mature, and Mexico is a natural sink for the U.S., Villarreal said, noting that his country’s supplies are rapidly being depleted and are bedeviled by high quantities of nitrogen. As the Mexican gas market goes, so goes the electricity market: Half of the country’s generation capacity (68 GW) comes from combined cycle plants.
“If the USA no longer considers Mexico a free trade partner [under the North American Free Trade Agreement], then exports will require a public-interest review … and then an environmental review,” Singer said. “Getting a permit to export gas to Mexico today is a very simple process. Representing the Mexican government, if we can’t get that gas, it will really be problematic for the system. But it’s also really problematic for Texas.”
But Villarreal prefers a more optimistic outlook.
“I think the underlying assumption is that the gas trade between Mexico and the U.S. will continue to flourish,” he said. “No investment on the gas infrastructure has been stopped. Nobody is saying, ‘Oh, don’t build that pipeline.’ On the power side, we’re working under the assumption that gas will not stop flowing from the U.S. into Mexico.”
MISO and PJM staff broke their silence Tuesday on ongoing efforts to solve the RTOs’ pseudo-tie congestion double-counting problem.
At a Feb. 28 MISO-PJM Joint and Common Market Initiative meeting, Kevin Vannoy, MISO director of forward operations planning, said the RTOs would solve the double counting of congestion for pseudo-tied resources in the near term by providing congestion rebates, while they would develop a way to allow pseudo-ties in the day-ahead scheduling process by 2018.
The fix may also be applied to pseudo-ties between MISO and SPP.
“MISO now has over 5,000 MW of pseudo-ties in and out [to PJM and SPP] that could be subjected to this congestion overlap,” Vannoy said.
MISO and PJM said they hope to roll out the first phase of the changes by June 1. They will include accounting for market flows in market-to-market settlements so attaining balancing authorities have enough revenue to issue refunds. The congestion overlap will be addressed by allowing attaining BAs to provide congestion rebates for generators.
Beginning in June 2018, the RTOs plan to have Tariff and joint operating agreement changes in place that let pseudo-ties schedule and settle in the source BA’s day-ahead market. The day-ahead coordination will take significantly more work than the near-term rebate plan.
“Right now, the day-ahead markets in MISO and PJM might not be aligned,” Vannoy said, adding that each RTO is only aware of the other’s constraints in real time.
MISO and PJM officials acknowledged that creating a rebate process by June 1 is ambitious. “This is a very aggressive timeline. For something to be in place by June, we have to work on Tariffs and JOAs,” Vannoy said. He asked for stakeholder comments by March 7.
Both MISO and PJM staff said they could convene a special meeting to discuss the proposal before the next scheduled Joint and Common Market meetup in May.
SPP Also?
The process could also be applied to MISO and SPP’s pseudo-tied generation and load. Unlike MISO and SPP, MISO and PJM don’t share any pseudo-tied load; all pseudo-ties are generation-based. Vannoy said the proposed rules could apply to MISO and SPP’s pseudo-tied generation and load “to the extent that we can get to a solution.”
Solution to FERC Complaints
Vannoy said MISO and PJM will also discuss the proposed solutions with two municipal power agencies and a generator that have filed complaints with FERC over the double counting to “explore resolution outside FERC.”
Tilton Energy, the owner of a 180-MW natural gas generator in Eastern Illinois, filed a complaint in August arguing that MISO is violating its Tariff by assessing congestion and scheduling fees on Tilton’s pseudo-tied transactions that have already been assessed by PJM (EL16-108).
In a late December complaint, the Northern Illinois Municipal Power Agency asked for a “full evidentiary proceeding involving PJM, MISO and the numerous pseudo-tying entities being harmed by the implementation of MISO-PJM pseudo-ties” (EL17-31).
And in January, American Municipal Power asked FERC to stop PJM from collecting charges from generators pseudo-tied out of the MISO balancing authority area where congestion charges were already assessed (EL17-37).
MISO Assistant General Counsel Michael Kessler has said FERC might combine the complaints.
Asked whether the RTOs would share with stakeholders details of their discussions with the plaintiffs, MISO Managing Assistant General Counsel Erin Murphy said the current meeting’s discussion might solve the complaints.
“I can’t say that there won’t be separate discussions,” she added.
Generator Skeptical
Tilton representative Elena deLaunay asked why PJM would be the appropriate side of the double count to be refunded, saying that MISO’s congestion charges were more inappropriate for PJM-based Tilton. She asked why PJM should have to provide refunds when its congestion is in the market the generator is being settled in, is created through the market-to-market process and flows through the make-whole calculation.
“We are being dispatched into price signals on the MISO side that we can’t follow as a PJM resource,” deLaunay said.
She also said the long-term solution to solve congestion double counting may be flawed: “Forcing us to speculate on which market we will be dispatched in [day-ahead or real-time] can create additional risk rather than mitigating it.”
Vannoy said the rebate will be based on physical transmission usage charges, and not on a pseudo-tie transaction basis. He also said MISO already provides congestion rebates through financial transmission rights, so he didn’t see it as “appropriate” that the RTO would only charge once and offer rebates twice.
Stricter Rules Coming
Both PJM and MISO are also focused on introducing stricter pseudo-tie rules.
Vannoy said MISO’s more stringent pseudo-tie process will be filed with FERC in the “near term,” despite staff putting the proposal on hold to better explain it to its stakeholders. (See “RTO Delays Filing Pseudo-Tie Proposal,” MISO Advisory Committee Briefs.)
Tim Horger, manager of interregional coordination at PJM, said his RTO will soon file its own more stringent pseudo-tie rules with FERC as well. Last month, stakeholders approved more stringent rules for new pseudo-tie applications but declined to endorse them for existing pseudo-tied units. PJM announced last week that it is going to file the new rules for FERC approval for both new and existing pseudo-ties. (See PJM to Tighten Pseudo-Tie Rules Despite Stakeholder Pushback.) A first-ever PJM pseudo-tie pro-forma agreement, however, was postponed last week after stakeholder concerns.
PJM and MISO pseudo-tied 2,061 MW of transfers for the 2016/17 planning year, compared with 156 MW during the previous year.
The increased pseudo-ties have produced more congestion and brought more attention to pricing discrepancies along the border between the RTOs, which can result in revenue imbalances between RTOs and increased uplift payments in addition to the double counting of congestion. The RTOs last year said MISO would use data from December 2016 to begin an analysis of pseudo-tie congestion in mid-2017.
The RTOs will also adopt a new common interface definition beginning June 1, moving from about 1,800 nodes inside PJM to a common interface consisting of 10 nodes close to the seam. Beibei Li, of MISO’s market evaluation and design team, said the change will reduce congestion overlap.
“We’re moving from a fairly large interface definition to something closer to the seam,” Li said.
A MISO 2016 study shows the new common interface definition affects real-time and day-ahead prices by less than $5/MWh in almost all cases, she added. The interface definition change is meant to eliminate overlapping congestion pricing incentives.
“The price incentive on June 1 shouldn’t differentiate all that much,” Li said.
The RTOs have made 23 successful day-ahead firm-flow entitlement exchanges since the exchange process began in January 2016. None of PJM’s 15 requests or MISO’s eight have been refused by the other RTO. (See “Regions Begin FFE Exchanges,” MISO/PJM Joint and Common Market Meeting Briefs.)
ERCOT’s latest seasonal assessment of resource adequacy (SARA) indicates ample generation for spring, with more than 82 GW of generation for an expected peak demand of 58 GW.
Nearly 1.5 GW of new gas-fired, wind and solar generation has become operational since the preliminary spring SARA was released in November.
Texas Wind Farm | Target
A preliminary summer SARA anticipates a new record peak of nearly 72.9 GW, with 81.6 GW of capacity. That would break the mark of 71.1 GW set last year on Aug. 11. ERCOT said it expects another 2.5 GW of new gas-fired and 1.6 GW of wind and solar generation to come online before the June-September season begins.
ERCOT Senior Meteorologist Chris Coleman is predicting another hotter-than-normal summer in Texas this year. He said during a media conference call last week that the state is coming off what may be its warmest winter on record, and he does not expect any significant changes in the “warming trend.”
Panda Power’s 758-MW Sherman combined cycle generator in Sherman, Texas, went online in 2014. | Panda Power Funds
“Eight or nine of the past summers have been hotter than normal,” he told the ERCOT Board of Directors in January. “That’s just been the trend. It would really be going out on a limb to forecast a mild summer for Texas this year.”
LAS VEGAS — Increased adoption of behind-the-meter generation is complicating short-term load forecasting across the Western Energy Imbalance Market (EIM), especially in the Arizona Public Service area.
The challenge is caused by the unpredictability of cloud cover, which can cause sharp and sudden drops in solar production.
“In the past, cloud cover was always a variable that came in for load forecasting, but it was really interrelated to temperatures,” Amber Motley, CAISO manager of short-term load forecasting, said during a March 1 meeting of the EIM Governing Body at The Palazzo hotel.
The conventional understanding: Clouds would move over an area, causing temperatures to fall, which would in turn reduce system load.
“Now, when you get high penetration levels of rooftop solar, there is a point in time when clouds come over and your [net] load is going to increase instead of decrease” because of reduced output from rooftop solar, Motley said.
A Caveat
Motley offered one caveat to that assessment: When daily temperatures average about 80 degrees Fahrenheit, temperature is still the main driver of the load forecast.
Under those conditions, air-conditioning load still drives enough electricity consumption that a cloud system causing a 10-degree drop in temperatures is going to reduce load.
Further complicating matters is humidity, which causes air conditioners to work harder and support load even under cloud cover. The situation is especially problematic in summer when monsoon moisture is thrown into the mix.
“You really have a question to ask yourself: Is my load going to increase because I am losing the rooftop solar, or is it going to decrease because I have a 10-degree temperature drop?” Motely said. “And we’ve seen both situations happen.”
Motley called APS the “most challenging load-forecasting region” within the EIM.
“It has a combination of a significant amount of rooftop solar, which is a driving factor, combined with some of those strong monsoon days in the summertime,” she said.
APS began transacting in the EIM last October, after the summer solar and monsoon peaks. But CAISO began running EIM load forecasting models ahead of the go-live date, giving operations staff an indication of what to expect this summer.
High Error Rates
So far, even outside the summer months, short-term load forecasts for the APS area are recording relatively high error rates compared with other EIM balancing areas (see chart). In November, the region’s hour-ahead forecast error rates reached nearly 2%, falling to 1.5% the following month. NV Energy has had similarly high error rates in the summer because of the prevalence of dust storms — a phenomenon that affects Arizona as well. The error calculations represent the average deviation between hour-ahead forecasted load and actual load.
The ISO’s goal is to keep error rates below 1%, Motley said, adding that such accuracy is not always attainable in some regions.
Graph shows the hour-ahead load forecast error rates for the EIM balancing areas outside CAISO during 2016. APS errors have outpaced those of other regions since the utility joined last October. | CAISO
“If you have more rooftop solar, your accuracy is going to be worse because you now have another characteristic behind the scene that is influencing it,” Motley said.
She pointed out that short-term load forecasting is an important component for market optimization and reliability. It also is used as a key input for dispatch operation functions such as unit commitment, economic dispatch, fuel scheduling and generation and transmission maintenance.
EIM Governing Body member John Prescott wondered if there was a “nexus” between load forecasting errors and the high number of flexible ramping test failures observed in the EIM late last year — particularly in APS. (See EIM Sees Sharp Increase in Flexible Ramping Test Failures.)
“There are several factors that play into that and we have to isolate each one to see what’s driving it,” said Justin Thompson, director of resource operations and trading at APS. “But load forecast is one piece of it. Also, how well have [we] forecasted wind? … How well [have] we forecast the solar output?”
Phoenix Baseline?
Alyssa Koslow, a regulatory analyst at Salt River Project, said she had heard CAISO was using Phoenix as the baseline for forecasting for Arizona, despite the fact that APS’s territory extends into high-elevation areas.
Motley clarified that the ISO’s approach to forecasting is more comprehensive than that.
“We have multiple temperature stations within Arizona, and [the load forecast] is always driven by the temperature station that’s closest to where your load pattern moves the most,” Motley said. “So we work with all of the EIM entities on which station in which area moves the most for your load and then we incorporate that into the design.”
“One of the problems with models is ‘garbage in, garbage out,’” said Clay MacArthur of Deseret Power. “There’s a lot of behind-the-meter generation going on. How do you aggregate” the capacity?
Motley responded that the ISO takes a bottom-up approach that starts with the zip code and capacity for every interconnection on the distribution system. That information lays the foundations for system load forecasts for individual areas.
“And then we forecast the irradiance — which is essentially the amount of sunlight that’s going to come from the atmosphere to the roof for that resource — and we put that into the forecast as its own variable,” Motley said.
Neural Net
That last point is important for CAISO’s “neural net” forecasting method, which relies on the dynamic interplay between “highly interconnected processing elements” — the data fed into the model. As Motley explained, the neural net is modeled on the human brain and can synthesize copious amounts of information and “learn” to weight the importance of certain factors over others in their predictive processing.
“Storing the information by technology type is very important so that the neural net can have the correct connections,” Motely said. If that information gets “blended in with the rest of the model,” then the neural net has a difficult time distinguishing whether it was a change in temperature or solar output that caused load to move up or down.
CAISO continues to seek ways to improve its load-forecasting model, Motely said. Future improvements could include having EIM participants share their own load forecasts to provide comparisons, as well as having them provide balancing area information about demand response, hydroelectric behavior, rooftop solar and irrigation patterns.
“Can we fix everything? No, it’s forecasting — it’s good job security,” Motley joked. “But are there some things that we can fix? Yes, there are some things.”
CenterPoint Energy said it is continuing to evaluate an offer for its ownership share in Enable Midstream Partners, and it expects to “clarify” its position in the third quarter.
The Texas company has a 55.4% stake in the gas gathering and processing venture with Oklahoma City-based OGE Energy. CenterPoint is considering an offer to purchase its share, but it could also spin off the business or continue to manage its position.
“If we determine that neither a sale nor a spin would fulfill our criteria, our third path will be to maintain our stake in Enable and continue to support efforts to reduce exposure to commodity price influences,” CenterPoint CEO Scott Prochazka said.
OGE made a second offer for CenterPoint’s stake on Feb. 15 under its right of first offer (ROFO), along with an unnamed partner. CenterPoint, which rejected OGE’s first offer in September, has until June 15 to make a final decision.
Prochazka said CenterPoint is continuing its “dialogue with interested parties” and it will “evaluate OGE’s recent offer made pursuant to the ROFO terms of our partnership agreement.”
“While the process is taking longer than originally anticipated, we expect to clarify which path we are on by the second-quarter earnings call,” he said.
Prochazka’s comments came during a Feb. 28 conference call with financial analysts following the company’s fourth-quarter earnings announcement.
Q4 Earnings Fall Short
CenterPoint fell short of analysts’ expectations, reporting fourth-quarter net income of $101 million ($0.23/share), compared to 2015’s fourth-quarter loss of $509 million (-$1.18/share). Zack’s consensus estimate was 29 cents/share.
The 2015 results included impairment charges totaling $984 million from its midstream investments. The company attributed the turnaround to rate increases and customer growth in its electric and gas utility businesses.
For the year, the company reported net income of $432 million ($1/share), compared to 2015’s loss of $692 million ($1.61/share).
CenterPoint reiterated its 2017 guidance of $1.25 to $1.33/share.
The company’s stock gained $1.99/share in the four days after the earnings announcement, ending the week at $27.90. CenterPoint shares have risen more than 13% since the beginning of the year — doubling the 6.4% increase in the Standard & Poor’s 500 index — and are up 43% in the last 12 months.
Executive Appointments
On March 1, the company announced three executive appointments: Scott Doyle as senior vice president of natural gas distribution; Joe Vortherms, as senior vice president of CenterPoint Energy Services; and Jason Ryan, vice president of regulatory and government affairs. Doyle and Vortherms will report to Prochazka. Ryan will report to General Counsel Dana O’Brien.
NYISO CEO Brad Jones and Public Service Commission Chair Audrey Zibelman told New York legislators they are not concerned about replacing the capacity of the 2,069-MW Indian Point nuclear plant, saying energy efficiency, transmission upgrades and the ISO’s wholesale market will ensure reliability.
Jones said that the grid operator has many options and “plenty of time” to resolve any reliability issues arising from closing the plant. In an aside, he also said the ISO is considering requiring new gas-fired generation to have dual-fuel capability.
NYISO has yet to receive a formal notice of deactivation of Indian Point, which would trigger a 90-day assessment period, but Jones told legislators during an eight-hour hearing Feb. 28 that he expects one will be filed in the coming months.
Joint Hearing
The State Assembly’s Committee on Energy held a joint hearing with the State Senate’s Committee on Energy and Telecommunications on the plant, located on the Hudson River 30 miles north of New York City. Plant owner Entergy and Gov. Andrew Cuomo announced an agreement in January to shut down Unit 2 in 2020 and Unit 3 in 2021. Unit 1 ceased operations in 1974. (See Entergy to Shut Down Indian Point by 2021.)
Left to right: Sen. Griffo, Rep. Paulin and Rep. Palmesano | New York State Committee on Energy & Telecommunications
Assembly committee Chair Amy Paulin (D) asked how the ISO evaluates the reliability effect of a facility going offline. Jones said that several factors influence the assessment process, mainly the fast-changing power system itself.
“Literally, the system is changing as much as it ever has in the past,” Jones said. “For example, we have new transmission, some that is under construction, as well as transmission that is in the process.”
He also noted increased energy efficiency and production from rooftop solar panels as well as “load shifting” by some market participants.
Senate Committee Chair Joseph A. Griffo (R) asked Jones whether the state’s goal of having renewables provide 50% of its electricity by 2030 was realistic. Jones said the goal was “ambitious, but achievable.”
Dual-fuel Requirement Coming?
Paulin asked the CEO to pinpoint the possible outcomes of a reliability assessment on Indian Point’s closure. Jones said that in the event of a reliability concern, the ISO would first approach the market to find solutions. If the market failed to find a solution, the next step would be to look for a regulatory fix.
Zibelman and Richard Kauffman, Chairman, Energy and Finance for New York testify before the joint committee | New York State Committee on Energy & Telecommunications
“Now, one of the options for the replacement of Indian Point would be to have additional gas units that come online to replace that,” Jones said. “There are a variety of different scenarios that I think are feasible. If the replacement generation does come from natural gas, we have been concerned at the NYISO, as we rely more upon natural gas, about the reliability of the supply of the gas itself. And so we’ve begun to look at … whether we should and could require generators throughout New York to have a dual-fuel supply.”
Planning Since 2011
Zibelman | New York State Committee on Energy & Telecommunications
Zibelman said the state has been planning for Indian Point’s closure since at least 2011, citing the AC Transmission project, which should begin construction in 2019 and be operational by summer 2022. She said new or mothballed generators will enter the ISO market if needed.
“New York has had a really good history of power plants getting built in response to market” demand, she said, citing the 6,000 MW of new plants added since the NYISO markets began.
“I’m not concerned about the replacement power. We have a robust market. There’s a lot of capital. People are very interested” in building new plants, she continued. “That plus the work we’re doing on energy efficiency and demand response and the transmission — all of those in combination is what makes me extremely comfortable that we’re not going to have a scarcity issue.”
She noted that New York’s wholesale power prices declined by 25% between 2012 and 2016, thanks largely to cheap natural gas. Over the same period, energy efficiency has caused the ISO to reduce its 2021 peak load forecast by almost 7% to 33,555 MW. Thus, she said, the plant’s closure should have a “negligible or no adverse” impact on consumers’ bills.
“Since prevailing wholesale prices are now lower than the cost of existing nuclear generation, it is anticipated that any new replacement power in the long run will be cheaper than continuing to buy power from Indian Point,” she said.
Worries over Economic Impact
Twomey | New York State Committee on Energy & Telecommunications
Also testifying was T. Michael Twomey, vice president of external affairs for Entergy’s wholesale power business, who was questioned about the company’s decommissioning plans and its offer to relocate laid off plant workers.
Much of the hearing was focused on the economic impact of the plant’s closure, primarily the loss of the plant’s property tax revenues and its 1,050 jobs.
On the morning of the hearing, Cuomo announced the formation of a task force to ease the impact on the community. “The task force will partner with local governments to address employment and property tax impacts, develop new economic opportunities” and retrain the work force, the governor’s office said in a news release. “The task force will also monitor compliance with the closure agreement, coordinate ongoing safety inspections and review reliability and environmental concerns, among other issues.”
LAS VEGAS — The West-wide forum created by CAISO to foster discussion about Energy Imbalance Market-related issues outside the ISO’s normal stakeholder process is worth preserving — and developing further.
That was the general consensus of stakeholders and EIM Governing Body members who gathered at The Palazzo hotel last week to discuss the fate of the Regional Issues Forum (RIF), which was established in 2015 as the ISO began to build momentum for “regionalization” — the push to expand into other parts of the West.
“We all value what the RIF has been doing,” Governing Body Chair Christine Schmidt said during a Feb. 28 joint meeting that included fellow body members, RIF representatives, industry participants and interest groups. “We value the promise of what the RIF can do going forward.”
Speaking in her capacity as a Washington state utility commissioner, Ann Rendahl — chair of the EIM’s Body of State Regulators — voiced her support for the RIF as someone “who is coming into this market new and learning a lot.”
“The Regional Issues Forum discussions have been very helpful, because you are all participating in the market and you have experiences that are helpful for us to learn and hear, in addition to the formal stakeholder processes that the ISO puts on,” Rendahl said.
Accolades notwithstanding, uncertainty still looms about the future role for the forum, what formal structure it should assume and how it should interact with the Governing Body.
Doug Howe, the body’s vice chair, referred to it as “the existential question of ‘What’s the RIF?’”
RIF representatives, called “sector liaisons,” have committed to answering that question and developing an operating framework for the group in time for the Governing Body’s July meeting.
“The liaisons don’t see a lot of barriers to getting this done in an expedited way,” said Tony Braun, RIF chair and a liaison representing the publicly owned utilities sector.
Informal Body
The RIF was conceived under the EIM charter as an informal body to enable industry stakeholders and the public to discuss wide-ranging issues related to the West’s only real-time energy market. (See PacifiCorp Offers Lessons for Future EIM Participants.)
The forum is organized by 10 liaisons representing five industry sectors: independent power producers and power marketers; transmission-owning utilities; publicly owned utilities; consumer advocates; and balancing areas neighboring the EIM — the last of which is a diminishing group as the EIM grows, Braun joked. CAISO planned for the RIF to meet about three times a year but required no set schedule.
According to the ISO, “The forum may produce documents or opinions for the benefit of the EIM Governing Body, ISO Board of Governors and the ISO,” but it sits firmly outside established stakeholder processes.
The EIM’s governance documents call for the RIF’s role to be re-evaluated by next month, which was the primary reason for the Feb. 28 joint meeting.
A key question in the re-evaluation: How should the RIF run the process to re-evaluate itself?
“Should this be an ISO-run stakeholder process in the traditional fashion?” asked Braun. “Is this something that the liaisons should take ownership of? What should be the liaisons’ role in putting together the recommendations and things like that, if any?”
Schmidt said she didn’t think the RIF’s evaluation was ever intended to become part of an ISO stakeholder process.
“I think the general consensus [among CAISO and EIM leaders] is that the Regional Issues Forum is the Regional Issues Forum,” Schmidt said. “However the re-evaluation needs to take place, this is in your control and is in your span of control and authority, and you should actually go through that process as a Regional Issues Forum issue.”
Speaking on behalf of her company, RIF liaison Sara Edmonds, general counsel at PacifiCorp Transmission, supported the general independence of the RIF, but she noted that the group has no funds or processes to post material coming out of its meetings.
“We’re happy as the liaisons to kind of be the muscle to pull together the substance [of the re-evaluation], but we’re still going to need the ISO vehicle to get the information out [and] help us with the meetings,” Edmonds said.
Ellen Wolfe of Resero Consulting, representing the Western Power Trading Forum (WPTF), backed Edmonds’ view. The WPTF sees “a lot of value” in the continuation of the RIF and agrees with the bottom-up approach to re-evaluation, she said.
‘Grass-Rootsy’
“We do like the idea of the RIF being very ‘grass-rootsy,’ so to speak, but also appreciate the ISO providing the infrastructure for posting comments and market notices and so forth,” Wolfe said.
Howe sought more clarity on the process the RIF would adopt in its re-evaluation.
“So we know that is not going to be a formal ISO stakeholder process — which means a few things, but among them is that you’re not going to start with an issue paper that’s going to be delivered to you by the staff of the ISO,” Howe said.
“So, to some extent, either you’re going to have to deliver the issue paper, or you’re going to have to take in the comments, perhaps write a strawman proposal, and send that out for another round of comments.”
Howe wondered whether ISO staff would ultimately be charged with writing the strawman based on what RIF liaisons heard during the Feb. 28 meeting.
“In my mind, we’re either fish or fowl,” Braun responded. “So if this is a process that the RIF liaisons are going to take ownership of, then my colleagues as the liaisons need to pick up the pens and craft the issue paper of the first straw proposal.”
“We’re all devoting our time and energy to this because we think it’s important,” said RIF liaison Matt Lecar, principal at Pacific Gas and Electric. “But there is a lack of formal structure, and therefore a lack of funding and resources to do things like write the extensive issue papers and straw proposals that the CAISO staff otherwise would in a CAISO stakeholder process.”
Hands Off
On the question of who should be responsible for approving the RIF’s proposal for a framework, Governing Body members advocated a mostly hands-off position.
“I am not seeking to have authority over what the RIF does,” said Governing Body member Valerie Fong, adding that she wouldn’t want to be cut out of the RIF’s activities because of the forum’s educational value. “I won’t be offended if [RIF members] decide that the EIM Governing Body does not have a decision in this process.”
Howe seconded Fong’s sentiments, saying he didn’t see a role for the Governing Body to put its “blessing” on the RIF’s final proposal.
“The primary purpose of this [process] is to construct an organization that helps you all to be effective, and I just want to thank you for including us in that,” Governing Body member Carl Linvill said. “But as far as any kind of formal approval, I’m with what everybody else has said: I don’t think we need that.”
Fellow body member John Prescott said it was important for the RIF to be transparent.
“What I want is access to the knowledge,” Prescott said.
Schmidt reminded her fellow body members that the RIF is embedded in the EIM’s governing documents, meaning that decisions around the RIF will still be subject to some CAISO oversight.
“If there’s a resource impact, or any other impact on the ISO or the ISO’s Tariff, those are matters that will have to be decided by the EIM’s Governing Body and ultimately the [ISO’s] Board of Governors,” Schmidt said.
RIF as Author?
Another key issue facing the RIF: whether it will produce papers on issues coming before the EIM Governing Body.
Stacey Crowley, CAISO vice president for regional and federal affairs, affirmed that ISO staff would be willing to take down comments from a RIF meeting.
“We’re happy to help,” Crowley said, adding that it would be up to the RIF, however, to craft substantive policy recommendations.
Howe emphasized the need for the RIF to document the views arising within its discussions. “If you don’t turn this into a written product, these are conversations that get lost in the dark,” he said.
Jennifer Gardner, staff attorney with Western Resource Advocates, asked whether the RIF could play the role of flagging issues for the Governing Body that are not already being addressed in CAISO’s stakeholder process.
“Is there value, from the Governing Body’s perspective, in having something a little bit more formalized with the RIF?” Gardner asked. A more formal process would entail producing written comments, rather than just “casual dialogue” among RIF participants.
“Does the RIF have to come to consensus on everything?” Fong asked. “Does it have to be giving us an overall perspective from a RIF level? I’d say ‘no.’ I’m OK with the individual input” from RIF participants.
Howe agreed with his colleague and added his own perspective.
“For me, the value is the eyes and ears out in the field to flag issues which may not have risen to the level [of] the ISO yet,” Howe said. “What doesn’t have value for me would be for the RIF to try to turn itself into a formal stakeholder process, because we’ve already got that [within the ISO]. And that just wouldn’t provide additional value.”
VALLEY FORGE, Pa. — And the winner is … LS Power, again.
Warren Beatty wasn’t on hand, but PJM still received plenty of criticism Friday after planners reaffirmed — with some scoping changes — their previous selection of LS Power’s proposal for the contentious and long-awaited reliability upgrades on Artificial Island.
The island on the southwestern edge of New Jersey is home to three nuclear reactors owned by Public Service Enterprise Group, which have been forced to operate for years below capacity and in accordance with a complex operating guide.
Salem and Hope Creek Nuclear Generating Stations on Artificial Island
Last August, PJM’s Board of Managers suspended the project for additional review after PSEG raised a series of engineering concerns and increased the cost estimate for its portion of the upgrades by at least $135 million. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
Scope, Costs Reduced
At Friday’s special session of the Transmission Expansion Advisory Committee, PJM officials said their review confirmed that LS Power’s proposal for a 230-kV line from Artificial Island to a new Silver Run substation in Delaware was the best solution but that the interconnection point should be changed from the Salem plant to Hope Creek. The analysis also determined that a static VAR compensator (SVC) at the New Freedom substation and optical groundwire upgrades provided little benefit and were unnecessary.
The planners’ recommendations will be forwarded to the board for final approval.
In addition to eliminating those upgrades from the scope of work, planners recommended implementing a voltage schedule at the plants and revising the in-service date to June 1, 2020.
Much of the discussion on Friday focused on the project’s costs compared to those of the other finalist, a project proposed by PSEG subsidiary Public Service Electric and Gas that would follow an existing transmission route north through New Jersey.
PJM’s analysis found that LS Power’s project would cost $265 million, $11 million more than PSE&G’s. But planners said LS Power’s proposal, which contained hard cost caps, provided “greater cost certainty.” PJM’s Paul McGlynn, who oversees the project’s development, said PSE&G’s project also raised permitting concerns because it would run through the Supawna Meadows National Wildlife Refuge.
PJM planners reaffirmed their 2015 selection of LS Power’s 230-kV circuit line to Delaware as the fix for stability problems at Artificial Island in New Jersey. Planners, however, determined that the line should connect Artificial Island at the Hope Creek nuclear generator rather than the nearby Salem plant. | PJM
As approved in July 2015, the project was expected to cost $270 million to $283 million. The February 2016 update that prompted the suspension pushed the cost to $418 million with the Salem interconnection more than doubling to $152 million from a maximum of $74 million.
Replacing the Salem connection with one at Hope Creek will save $20 million, and eliminating the optical ground wire and SVC trimmed an additional $120 million. That brings the projected cost to $265 million, with a cost cap of $278 million — within the bounds of the original project cost estimates.
PJM also pointed out that LS Power has already spent about $6.5 million on preliminary work, so switching projects would mean writing off that expense as a sunk cost. The RTO acknowledged that PSEG has also spent money on developing work estimates for PJM regarding its project but “didn’t think” to quantify it, said Vice President of Planning Steve Herling.
Stakeholders from PSEG and Dominion were among those criticizing PJM’s new recommendation.
More ‘Granular Review’
PJM said the suspension allowed time to conduct a “more granular review and re-evaluation” of the project, including additional site visits and marine and terrestrial surveying, a review of permits, property rights and scheduling issues and preliminary engineering.
Planners determined the optical groundwire and related line relay changes would not impact the site’s operating guide or improve stability margins because of the timing of the most critical bus fault’s clearing. They said if a need is identified for the upgrades later they would be pursued as a separate project.
The SVC was replaced with a recommend voltage schedule for Salem and Hope Creek requiring operation at a minimum of 527.5 kV, a level PJM said was “maintained in nearly all conditions since 2012.”
PSE&G insisted its proposal was “more robust” than LS Power’s, providing larger stability and system reliability margins and — because it would employ a 500-kV line — more than three times more capacity than its competitor’s 230-kV line.
PSEG’s nuclear division sent the PJM board a letter March 2 warning that it has an option to build another reactor at the Hope Creek station and that the connection at Hope Creek might have to be moved if it moves forward with another reactor. Herling said PJM has no control over that and that future work at the site would need to be reviewed on a “case-by-case” basis.
LS Power’s Sharon Segner said it’s not an “apple-to-apples” comparison because PSEG’s proposal excludes any overruns for environmental permitting and securing real estate rights, while her company’s includes risks for both. In addition, LS Power has already contracted for material portions of its project, so the revised, lower cost estimate of $133 million for its portion reflects some actual contractual numbers.
PSEG’s Jodi Moskowitz said that most of the costs in her company’s proposal are capped.
Old Dominion Electric Cooperative’s Mark Ringhausen said it was “deceiving” to use $265 million for LS Power’s project when that is only the company’s current estimate. The proposal is actually capped at $278 million. LS Power’s estimate assumes PSEG’s work at Hope Creek costs no more than $132 million. However, this portion of the project has no cost cap.
That wasn’t the end of the controversy, however. Delaware and Maryland officials have complained that most of the cost of the project would be allocated to ratepayers on the Delmarva peninsula despite the region receiving little benefit from the upgrade.
Last April, FERC approved the cost allocation for the project, but in June it said it would consider rehearing requests over whether PJM’s use of the solution-based distribution factor (DFAX) cost allocation method is appropriate for the project (EL15-95, ER15-2563). (See FERC Taking Second Look at Cost Allocation for 2 PJM Projects.)
The commission cannot resolve the dispute until new members are appointed to restore its quorum.
Next Steps
Herling said the board will be educated about all of the cost estimates through comprehensive documentation, and “I guarantee they’ll read all of it.”
The next board meeting is scheduled for April 6, so PJM asked that all stakeholder comments on the recommendation be filed by March 31. Stakeholders expressed concerns that PJM won’t have published its comprehensive whitepaper on the topic by then, so all comments will have to be based on existing documents.
