OGE Energy on Thursday reported second-quarter earnings that beat Wall Street’s expectations and reflected economic growth in its service territory.
The Oklahoma City-based company, parent of Oklahoma Gas and Electric, disclosed earnings of about $100 million for the quarter ($0.50/diluted share). A year ago, the quarterly earnings were $111 million ($0.55/share).
Zacks Investment Research’s survey of financial analysts had projected earnings of 48 cents/diluted share.
CEO Sean Trauschke said the company added 8,000 more customers than it did a year ago, doubling its historic 1% load-growth rate.
“It appears our rate and economic development efforts are paying dividends,” he told analysts during a conference call, noting more than a dozen companies have announced new investments in the region. “Our rates and high reliability are often cited as factors in their decision-making process.”
OGE CEO Sean Trauschke | OGE Energy
Mild temperatures and severe flooding reduced OG&E’s contributions to earnings from 46 cents/share to 37 cents/share when compared to 2018’s second quarter. Oklahoma’s spring thunderstorms left 20 substations partially or fully submerged, Trauschke said.
Enable Midstream Partners, in which OGE holds a 50% general partnership interest, had earnings of 13 cents/share, up from 11 cents a year ago. The joint venture with CenterPoint Energy has contributed more than $1 billion in cash distributions to OGE since its formation in 2013.
“Both of our businesses performed well in the second quarter and are on plan for the year,” Trauschke said.
OG&E has a rate case before the Oklahoma Corporation Commission that would allow it to recover about $600 million for installing scrubbers at its Sooner Power Plant and converting two coal-fired units at its Muskogee Power Plant to natural gas.
“Once the final order is issued, this decade of environmental compliance will be complete,” Trauschke said. “It’s required hundreds of millions of investment dollars. … Since 2011, we have invested more than $6 billion in our system, and customer rates are lower than they were eight years ago.”
OGE reiterated its year-end guidance of $2.05 to $2.20/diluted share.
The company’s stock opened Thursday at $42.33. It finished the week up at $42.87 after a late 26-cent drop.
MISO has signaled that it’s ready to address calls from its Independent Market Monitor and members to tighten capacity deliverability requirements, although some stakeholders are skeptical it can raise standards without increasing costs to customers.
The effort was launched last week with a new deliverability proposal for wind, solar and electric storage resources. The RTO draws a distinction between conventional and intermittent resources for deliverability.
The Monitor contends MISO doesn’t properly account for capacity deliverability because its loss-of-load expectation (LOLE) study assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, the RTO allows resources to demonstrate deliverability only up to the unforced capacity (UCAP) levels, which tend to be about 5 to 10% below full ICAP levels.
The Monitor has said MISO should assess deliverability for all capacity resources based on full ICAP. Potomac Economics staffer Michael Chiasson said the Monitor first became aware of “MISO’s interpretation of its Tariff” after the 2016 auction, when it determined that one unit came up short by “tens of megawatts.” However, he said the Monitor’s analysis of 2019/20 capacity auction results found that no zones went into capacity shortages because of MISO’s capacity deliverability structure.
At a Resource Adequacy Subcommittee meeting Wednesday, MISO floated three options to address the issue:
Use a resource’s transmission service request value as the maximum historical output for the average capacity factor, which would stand to reduce capacity credits;
Require deliverability up to the resource’s UCAP divided by MISO’s “PKmetric,” which is the average capacity factor for each commercial pricing node over the eight daily peak hours since 2005; or
Require resources to be deliverable to the highest megawatt output value during the eight daily peak hours for the last three years.
MISO’s Darrin Landstrom said the three-year option has the most potential to be variable: “It’s going to be there for three years, then we’ll re-examine it. It could go up or down.”
The Coalition of Midwest Power Producers (COMPP) last year filed an unsuccessful complaint over the apparent gap in MISO’s accounting of capacity deliverability. (See FERC: No Merit in MISO Deliverability Complaint.) The group argued that the RTO’s “deliverable to load” requirement in the Tariff should be interpreted to require capacity resources to have firm transmission service up to their full ICAP levels. FERC rejected that argument, saying MISO had no Tariff provision to support the group’s reading and that there was no evidence the existing practice places reliability at risk.
Necessary?
But some stakeholders think it’s unrealistic to assume MISO has enough firm transmission to go around to allow for an increase the deliverability requirement. They also said the RTO should prove that its UCAP deliverability requirements are a problem before making proposals.
“You really think in some of these zones we’re going to be able to purchase firm transmission service up to our load? … I don’t have any hope that this will be the case,” Madison Gas and Electric’s Megan Wisersky challenged.
“That’s a good point,” MISO Executive Director of Resource Planning Patrick Brown said.
“And when do you want resource adequacy? Or do you want to bleed us dry for [cost of new entry]?” Wisersky continued, referring to the risk of putting more transmission service requests into MISO’s already overstuffed interconnection queue when there’s currently not sufficient transmission available to handle proposed generation.
“That’s a good point,” Brown repeated.
“This is a serious issue and has the potential for serious rate implications. We are potentially looking at rate shock for our retail customers,” Wisersky said.
MISO Director of Resource Adequacy Coordination Laura Rauch said the goal is for resources to carry firm service up to the output they would have in real-time operations. “We do think that there are resources that don’t have deliverability up to their summer peak day,” Rauch said during the Market Subcommittee meeting in July.
But Clean Grid Alliance’s Natalie McIntire questioned whether MISO needed a solution at all.
“My general philosophy is we’ve identified a gap, and we can address it,” Brown said. “Several years ago, when we had a 30% reserve margin, gaps like these weren’t a big deal. We don’t want to wait until this becomes a problem to address it.”
“I think this is a little bit half-baked,” WPPI Energy’s Steve Leovy said of the proposal.
Landstrom said MISO isn’t wed to any of the three options just yet. Brown also said that MISO will continue to study the impact on zones for any new deliverability proposal.
“We aren’t going to push someone into an insufficient position where they don’t have time to react,” Brown said.
The judge overseeing PG&E Corp.’s Chapter 11 bankruptcy questioned the utility’s attorney last week over a proposed compensation package that includes about $11 million in performance-based bonuses for 12 executives.
At a hearing in San Francisco on Friday, Judge Dennis Montali, of the U.S. Bankruptcy Court for the Northern District of California, said he took issue with the language included in a PG&E court filing supporting its key employee incentive program (KEIP), filed with the U.S. Securities and Exchange Commission in late June.
The utility told the court its board of directors’ compensation committee had “determined that the KEIP was necessary to appropriately incentivize and align the KEIP participants’ goals and performance with those of the [company] and … to provide the KEIP participants with the opportunity to achieve a market rate of compensation, but only if the KEIP performance goals are achieved.”
PG&E headquarters
Montali told PG&E attorney Stephen Karotkin that he had a problem with the phrase “appropriately incentivize,” recalling that the utility’s equipment was responsible for some of the worst wildfires in the history of the state.
“If they’re not incentivized enough, they ought to find another job, frankly,” the judge said.
Karotkin defended the bonuses, saying they would only be paid if the executives met certain targets. He assured the judge that they were dedicated to safety and regaining state residents’ trust.
Montali also said he found it “troublesome” that the utility paid its new CEO, former Tennessee Valley Authority CEO Bill Johnson, a $3 million signing bonus without disclosing it to the court. Although the company disclosed the payment in an SEC filing and it was reported on in the press, it was paid before the company filed the KEIP with the court, which appeared to perturb the judge.
After a long back-and-forth with an attorney from the U.S. Trustee Program, who ultimately said he did not find the payment improper, Montali decided against ordering Johnson to disgorge the payment, though he scolded PG&E for being “too clever by half.”
CPUC ‘Protocol’ Talks Fail
Friday’s hearing was set to discuss the results of negotiations between the California Public Utilities Commission and several ad hoc groups of bondholders, insurers and wildfire claimants that have asked Montali to terminate PG&E’s exclusivity period — the time it has to offer a reorganization plan without the judge having to weigh competing proposals. The other stakeholders want the court to consider their own bankruptcy plans.
PUC attorney Alan Kornberg last month persuaded Montali to give the commission, Gov. Gavin Newsom’s office and the groups time to work out a “protocol” — a process and timeline for the commission to consider all the competing plans and file one with the judge. Kornberg said the effort could expedite the process by eliminating the need for Montali to review several plans.
Under Assembly Bill 1054, passed last month, the PUC must approve a bankruptcy plan by June 30, 2020, for PG&E to be able to access a $21 billion fund to pay wildfire claims. (See California PUC Jumps into PG&E Bankruptcy Fray.)
But on Friday, Kornberg reported that talks had broken down, with the groups apparently insisting that PG&E play no role in selecting a restructuring plan. Montali directed Kornberg and the several attorneys representing the other parties to the discussions not to give him details of the talks so as not to prejudice himself before he rules on the groups’ motions to terminate exclusivity on Tuesday.
Kornberg did say that several parties had told him they were confident the legislature would extend the June 30 deadline. An attorney for Newsom’s office called banking on that “an unintelligent move.”
Montali asked Kornberg if the PUC could begin to work on its own approval process simultaneously with the court. Kornberg said the commission needed a court-approved plan to consider; otherwise, it could waste time and resources considering a plan that might not ultimately be approved.
Earnings
The hearing came after PG&E reported earlier that day that it had lost $2.55 billion ($4.83/share) in the second quarter. The company posted a loss of $983 million ($1.91/share) for the second quarter last year.
The loss included a $3.9 billion pre-tax charge for estimated third-party claims related to the 2017 Northern California wildfires and the 2018 Camp Fire. The company has lost about $2.4 billion this year; it posted a profit of $136 million ($0.25/share) for the first quarter.
Total revenue for the second quarter was down about 7%, from about $4.2 billion in 2018 to about $3.9 billion this year.
“Items impacting comparability for the quarter also include enhanced and accelerated electric asset inspection costs; clean-up and repair costs related to the 2018 Camp Fire; legal and other costs related to the 2017 Northern California wildfires and the 2018 Camp Fire; and financing, legal and other costs related to PG&E Corp.’s and Pacific Gas and Electric Co.’s reorganization cases under Chapter 11 of the U.S. Bankruptcy Code,” the company said in a statement.
“Our primary focus areas are to further reduce the risk of wildfires in the communities we serve, to improve our safety and operational performance across the board, and to move expeditiously through the Chapter 11 process, which includes paying wildfire victims fairly and as soon as possible,” Johnson said. “We recognize we are operating from a deficit when it comes to public trust, and to regain that trust, we must sustain excellent operational performance day after day, month after month, year after year.”
HARTFORD, Conn. — About 40 environmental activists marched Wednesday in front of the headquarters of Connecticut’s Department of Energy and Environmental Protection to protest state regulators’ recent approval of a new gas-fired power plant in the town of Killingly.
The Connecticut Siting Council on June 6 approved construction of the 650-MW Killingly Energy Center by Florida-based developer NTE Energy, permitting the plant to emit up to 2.2 million tons of carbon dioxide each year.
Sierra Club volunteer Martha Klein led the protesters in a chant on the steps of DEEP headquarters: “Hey, hey, ho, ho, Katie Dykes has got to go!” — referring to the DEEP commissioner.
“I’ve got a simple one-word answer for why Connecticut keeps expanding fracked methane despite knowing that it’s destroying our climate: It’s ‘corruption,’” Klein said. “It’s equal opportunity corruption, for we’ve had both a Republican governor [John Rowland] and a Democrat mayor [Hartford’s Eddie Perez] go to jail.” Neither politician was convicted of illegal activity related to the energy sector.
Klein told RTO Insider that “when the state approves new power plants run on fracked gas or oil, that’s going to exacerbate climate change.”
Ann Gadwah, chair of the state’s Sierra Club chapter, said, “This plant is totally unneeded. New England doesn’t need the power, and Connecticut doesn’t need the power.”
Gadwah said regulators seem to have forgotten that the state legislature passed a law requiring DEEP to monitor air quality in the eastern part of the state after New York approved construction of the 1,100-MW natural gas-fired Cricket Valley Energy Center, which is slated to go online next year and the emissions of which would generally blow into Connecticut from its site just west of the state line.
RTO Scapegoat
James Albis, a senior advisor to Dykes, spoke to activists and reporters at the protest and handed out flyers with questions and answers on Killingly.
On why the plant is being built, DEEP said, “It was procured through the regional ISO New England capacity market auction to meet regional reliability needs. It will help address reliability needs in the winter because of its dual-fuel capability, allowing it to run on ultra-low-sulfur diesel during peak times when natural gas is constrained, which is a cleaner alternative to other baseload peaking generators.”
KEC Site Location | NTE Energy
In response to the question of who will pay for the plant, the department said the state “does not have any contractual obligations with Killingly. The plant cleared in the regional [ISO-NE] market that Connecticut participates in, but NTE (the developer) bears the risk of participating in the market and the potential for stranded costs as Connecticut moves to a zero-carbon future.”
Melinda Fields came to protest from Hampton, a few miles west of Killingly.
“I protested the Siting Council meeting too,” Fields said. “It seemed like they only wanted to help the company get what it wanted; like, ‘what can the state do for you?’”
The area’s state senator, Mae Flexer, submitted testimony stating that Connecticut Economic Resource Center data indicate that Killingly would become the second-largest power generation town in the state if the plant is built, behind only Waterford, site of the Millstone nuclear plant.
“This would be an enormous burden to place on the people and environment of Killingly,” Flexer said. “To require so much of the state’s electricity to be generated here and — along with it — to concentrate such a large percentage of the state’s pollutants and emissions from power generation in this town is grossly unfair.”
Veteran activist Cher Kapelner-Champ said she had been among 1,200 people arrested in 1977 for protesting the construction of the Seabrook nuclear plant in New Hampshire.
“They built Seabrook anyway, so why do I keep protesting?” she said. “As a great Hebrew scholar once said, we all just bring our one teaspoon of compassion — and you never know when the tipping point will come.”
PJM’s wholesale power markets remain “under attack” from those concerned about the retirements of legacy generators unable to profit in the face of ever-decreasing energy prices, the Independent Market Monitor said Thursday.
In its quarterly State of the Market report released last week, the Monitor — in a thinly veiled dig at PJM’s minimum offer price rule (MOPR) revisions pending before FERC — said there’s no reason to exclude competitive capacity offers from any generator, nor artificially increase energy prices to benefit struggling nuclear and coal plants.
“The value of markets is under attack, from those who think energy prices are too low and from those who think that market outcomes do not favor their preferred technology, whether it is nuclear, coal, wind or solar,” the Monitor said.
Instead, PJM should prevent the markets from reverting back to an integrated resource planning approach “that some would reimpose because markets provide technology-neutral incentives to all market participants, including those who will introduce technologies not yet in existence.”
“Markets continue to provide the most efficient way to organize the production of power at the lowest possible cost,” the report reads. “Markets are also the most efficient way to integrate state-supported renewable technologies.”
Record Low Energy Prices
The Monitor reported that energy prices decreased 35% to $27.49/MWh in the first six months of 2019, compared to the $42.44/MWh seen a year prior. Lower fuel costs contributed to nearly a third of the decline, while decreased load and lower mark-ups comprised the rest. These are the lowest load-weighted real-time energy prices ever seen in PJM, the Monitor said.
The lower prices drove down net revenues for all unit types, including: 65% for combustion turbines, 44% for new combined cycles, 87% for new coal plants, 30% for new onshore wind and 34% for new nuclear plants.
The last includes the subsidized Quad Cities and three other Exelon nuclear facilities in Illinois — Braidwood, Byron and LaSalle. Based on current forward prices, the Monitor said, all four of the plants will fail to recover their avoidable costs in two of the three forward years, with an average annual shortfall of 73 cents/MWh during the shortfall years.
Quad Cities nuclear plant | Exelon
Exelon told investors earlier this month that without substantive legislative action, the company will close unprofitable plants so as to not “damage the balance sheet sitting around for years with negative free cash flow or negative earnings.” (See related story, Exelon to Close Three Mile Island.)
The Monitor acknowledged PJM’s markets are imperfect and said a carbon price would provide a market-based solution to reducing emissions and supporting nuclear plants’ economics. But it said “the fact that some plants are uneconomic [without a carbon price] does not call into question the fundamentals of PJM markets. Many generating plants have retired in PJM since the introduction of markets, and many generating plants have been built since the introduction of markets.”
Energy Market Competitive, Capacity Market not
The Monitor said PJM’s energy market remains competitive while the capacity market does not — consistent with the Monitor’s conclusions in reports released in March and May. (See Energy Market Competitive in Q1, PJM Monitor Says.)
As an alternative to PJM’s MOPR for addressing the dilemma between “market solutions and potentially inconsistent state policy initiatives,” the Monitor again touted its proposed Sustainable Market Rule (SMR). (See PJM Monitor Reiterates Concerns in Quarterly SOM Report.)
Under the SMR proposal, all nonmarket resources could participate in the energy market without limits, with the capacity market used as a “balancing mechanism” for providing incentives for resources to enter and exit.
“The SMR approach to the capacity market design is simple, based in economic logic, based on the PJM competitive market design and does not require complex rule changes to implement,” the report reads. “The SMR would provide a straightforward way to harmonize federal and state approaches to the provision of energy, while respecting the distinction between federal and state authority. The SMR reaffirms the definition of a competitive offer in the PJM capacity market and removes noncompetitive barriers to the participation of renewables.”
The Monitor also criticized PJM’s energy price formation plan, saying that it guarantees double recovery for generation owners “by breaking the tight link between energy and capacity markets that has been essential to the success of the PJM market design.” It also accused the RTO of creating unintended consequences by pushing through substantial energy market revisions without any explanation of how such changes would “enhance or even maintain the competitiveness of the markets.”
The Monitor outlined five steps to address what it called legitimate concerns about price formation in the energy and reserves markets:
Consolidate the tier 1 and tier 2 synchronized markets.
Increase the scarcity price to reflect the highest generator energy offer allowed.
Increase the transparency of operator actions, with explicit pricing for defined actions.
Implement clear rules governing real-time pricing through the selection of real-time security constrained economic dispatch (RT SCED) and locational price calculator (LPC) cases. LPC, which uses the latest approved RT SCED case as its reference case, produces financially binding LMPs and reserve market clearing prices.
Develop a consistent definition of energy and reserves products in the day-ahead and real-time markets, including recognition of the appropriate role of demand-side resources.
“This should not be the end of the discussion, but the beginning of a longer, more complete discussion which would lead to incremental steps to improve markets,” the report concluded.
Recommendations
The Monitor provided three new recommendations for PJM stakeholders to consider:
Demand response reductions based entirely on behind-the-meter generation should be capped at the lower of economic maximum or actual generation output.
Load and generation located at separate nodes should be treated as separate resources.
FERC should require that the open firm flow entitlement (FFE) and firm flow limit freeze date issues be addressed at a technical conference, and that a deadline to resolve the issues that result from the freeze date be set. PJM, Outside Parties Slow MISO-PJM Freeze Date Thaw.)
ERCOT staff have laid out a plan to work with stakeholders in addressing a May pricing event that has led to a complaint filed with Texas regulators against the grid operator.
Kenan Ögelman, ERCOT’s vice president of commercial operations, met with the Wholesale Market Subcommittee on Wednesday and proposed three issues for further discussion with market participants, including potential changes to the grid operator’s price-correction methodology; adding filters, requirements or different standards to the external telemetry coming into ERCOT; and improving the communications structure around price corrections.
| Lone Star Transmission
Ögelman said staff would return to the WMS in September with an issues list. He said he expects “more topics than any solutions.”
“We’d like to give a high-level presentation and see if you have any other issues,” Ögelman said. “I think it’s important everyone see all the issues and where they’re going so we can get a solution.”
On May 30, prices briefly reached the $9,000/MWh maximum when the security-constrained economic dispatch system received bad telemetry data from Calpine. Staff quickly corrected the data, but they have refused to correct the prices because the data were external.
“Incorrect telemetry coming from outside ERCOT is not something we run corrections for,” Ögelman told the grid operator’s Board of Directors in June.
Aspire Commodities, an energy broker, has filed a complaint with the Public Utility Commission of Texas asking that generators refund the market $18 million (49673). (See ERCOT Asks PUC to Dismiss Trader’s Complaint.)
Morgan Stanley’s Clayton Greer, who has complimented ERCOT on its quick response to the pricing error, urged quick decisions in the future.
“You let us know you were not going to reprice that day. The market understands once you do that, it’s final,” he said. “If you could find a way to put into words what you did [on May 30] into the protocols, that would be optimal.”
“We want prices to reflect the fundamentals of the market,” Reliant Energy Retail Services’ Bill Barnes said.
Luminant Generation’s Ian Haley indicated his company preferred to see bad telemetry rejected.
“We don’t think ERCOT should be in the business of determining what is and what isn’t correct,” he said.
CARMEL, Ind. — MISO is working quickly to ensure its capacity resources are mostly accessible for the planning year after this spring’s auction cleared a Michigan generator scheduled to be on outage for the entire period.
The RTO proposed a provisional solution at the Resource Adequacy Subcommittee meeting Wednesday that would limit extended planned outages to fewer than 90 days to qualify for participation in the Planning Resource Auction. Additionally, resources expected to be unavailable for the first 90 days of the planning year would not qualify for PRA participation.
Cleared resources with planned outages lasting 90 days or longer must replace their capacity or be penalized at MISO’s approximately $250/MW-day cost of new entry. Currently, the RTO doesn’t impose any penalties for capacity resources that take extended outages.
“If you think about MISO’s resource adequacy construct, there is a reasonable expectation of availability,” Director of Resource Adequacy Coordination Matt Ellis said.
MISO plans to file the proposal with FERC by mid-October to have it in place in time for the 2020/21 PRA, an unusually fast turnaround for the RTO, which can spend several months to a few years formulating new Tariff language. MISO said it also plans to seek more fleshed-out outage rules for the 2021/22 auction.
Ellis said that while MISO may not be able to make a comprehensive filing now because it must examine several possible unintended consequences, it can impose a straightforward, 90-day requirement.
“It’s an incremental change. It’s intended to be a step in the right direction — something we can refine further as we go along,” Ellis said.
April’s PRA cleared a large generator in Michigan’s Zone 7 as a capacity resource for the 2019/20 planning year even though it is slated to be on an extended outage for the entire year. The Independent Market Monitor first criticized the move in June. (See “Extended Outages and the Capacity Auction,” Monitor Splits with MISO on Summer Readiness.)
Ellis said the 90-day requirement is meant to capture the possibility that a planning resource will be out for an entire season. Requiring availability in the first 90 days of the planning year also ensures that capacity resources will be available during summer months when availability is more critical. MISO planning years begin June 1.
Stakeholders immediately inquired about planned outages that come in just under the threshold, but Ellis said MISO is starting by drawing the line at 90 days.
“And honestly, when we discussed this internally, that’s the first thing that came up: ‘What if units take an 89-day outage?’” Ellis said. “What’s the bright line? We chose 90.”
Ellis said MISO will revisit its proposal if 88- to 89-day outages begin to become “habitual.”
When stakeholders asked what would happen if a generator extends an outage to 90 days or longer, Ellis responded it wouldn’t be retroactively penalized to cover replacement capacity. However, MISO and the Monitor would keep a sharp eye for resource owners that might be seeking to game the rule with sudden extensions. Under the plan, the Monitor would have Tariff authority to audit outages for physical withholding.
Stakeholders said the proposal could encourage generators to take forced outages — and the accompanying hit to resource accreditation — over taking a long-term planned outage that would exclude them from a capacity payment for a planning year or face having to replace the capacity at a high cost.
MISO has left the proposal open to other stakeholder comments through Aug. 23.
New York regulators on Thursday kicked off a proceeding to examine how to reconcile NYISO’s resource adequacy (RA) programs with the state’s renewable energy and carbon emission-reduction goals (Case 19-E-0530).
Chair John B. Rhodes
“This item to open an inquiry is important and timely,” Public Service Commission Chair John B. Rhodes said. “We at the commission have a duty to ensure safe and adequate power. Safe means safe, and adequate means, in this case, [that] there’s power when New Yorkers need it. … It’s becoming questionable whether the answers that were organized at least 20 years ago are in fact the best answers for the situation we face today.”
David Drexler, the PSC’s managing attorney, said “a major impetus” for the RA inquiry is New York’s recently passed Climate Leadership and Community Protection Act (A8429) — particularly its mandate that 70% of the state’s electricity be generated by renewable resources by 2030.
Commissioner Diane Burman said she understood the need to examine electricity issues, “but I do find it disingenuous to say that we have an obligation to do this when there are many other issues that we have an obligation to examine,” pointing to Consolidated Edison’s moratorium on providing new customers with natural gas hookups in Westchester County until it can ensure adequate supply to the region.
The PSC held its regular monthly session in Albany on Aug. 8, 2019.
“I think the chairman nailed it when he said that the current approach was set 15 to 20 years ago, and it’s based on the cost attributes of a fossil generator,” said Warren Myers, director of regulatory and market economics for the state’s Department of Public Service.
The inquiry will focus on answering several questions, including:
Are the state’s energy policies and mandates, such as those related to offshore wind, photovoltaics, other renewables and energy storage, compatible with NYISO’s RA mechanisms? If not, what issues are manifested? Also, if not, how could they be aligned? Do policies and market structure mechanisms result in safe, adequate service at just and reasonable rates?
Is an installed capacity (ICAP) product an effective long-term solution for RA given the required future generating resource mix, which may have lower marginal costs or different availability profiles than many current generation resources in operation? What are the salient attributes of such long-term solutions?
Is there a preferred mechanism for ensuring RA? What are the cost impacts and benefits to consumers under the various potential RA mechanisms?
Should alternative approaches be considered to ensure that procurement of generation resources is aligned with state policy goals? If so, which ones? Are there existing or proposed models that might be instructive, such as the state overseeing the RA portfolios of load-serving entities as in California, or should NYISO rules be restructured to accommodate state policies?
What is the state’s role with respect to RA matters?
What, if any, next steps should the commission take with respect to RA matters?
First of Many
Commissioner Diane Burman
Burman said she would ask the “elephant-in-the-room question,” wanting to clarify that the PSC’s new effort would not seek to “undo the role of the ISO” regarding RA, “but in fact is looking at how can we work on these issues.”
“The elephant is prematurely in the room,” Myers responded.
Drexler said, “Actually, from a staff perspective, we’re not prejudging any of the issues at this point. This is merely meant to start the inquiry.”
Commissioner James Alesi supported the inquiry, saying that “New York is already on its way to cleaner energy consumption.”
Commissioner Tracey Edwards
Commissioner Tracey Edwards said it was better to start asking the right questions now than later, “when we’d be doing so in a defensive posture.”
Attending his first session since being appointed to the PSC on July 19, Commissioner John Howard said, “The truth is, the ISO and its markets work today; the lights stay on; people get paid. If you’re an incumbent, things seem to be pretty well-ensconced. However, that doesn’t mean there aren’t holes that need to be examined. … I believe this will be the first of many inquiries.”
In an Aug. 8 blog post, Jackson Morris and Cullen Howe of the Natural Resources Defense Council welcomed the PSC’s inquiry and raised two points.
“A central concern held by many stakeholders, including NRDC, is that NYISO’s capacity market rules could prevent clean energy resources supported by state and local policies from selling in that market, thereby depriving these resources of an essential source of revenue. …
Commissioner John Howard
“Another concern is that NYISO’s rules undercount the value of cleaner resources like energy storage systems, as well as wind and solar, while over-crediting highly polluting power plants.”
Burman expressed additional concern that the proceeding seems to lack direction: “Ultimately, all we seem to be addressing is the capacity markets and buyer-side mitigation, and then taking a look at, in some fashion, whether or not we want to change those rules.”
The commission has asked interested parties to submit initial comments by Nov. 8. Commenters can file with the DPS by e-filing or by email to secretary@dps.ny.gov, or through the department’s Document and Matter Management System.
“Today’s order is the beginning of an important discussion on resource adequacy, and we look forward to engaging with the Public Service Commission throughout the process to share our expertise, information and ideas,” NYISO CEO Rich Dewey said in a statement.
NERC’s plan to streamline its top technical committees appears to face limited opposition, although officials indicated Thursday they are considering proposals to increase sector representation and lengthen the transition.
The new structure, to be discussed in detail at NERC’s quarterly meeting in Québec beginning Tuesday, would merge the Planning, Operating and Critical Infrastructure Protection committees into a new Reliability and Security Council (RSC). While the three technical committees have almost 120 voting members, the proposal would limit the RSC to 33.
Only two stakeholders made comments during a webinar Thursday on the proposal, both questioning why NERC hasn’t quantified the proposal’s supposed benefits. But NERC also has received written comments from a dozen stakeholder groups, who were nearly unanimous in calling for a longer transition and an increase in the number of sector representatives in the new organization. Some also questioned whether security issues should be combined with operations and planning.
A new Reliability and Security Council (RSC) would join the Reliability Issues Steering Committee (RISC) in reporting to the NERC Board of Directors under a proposed reorganization. NERC officials are apparently reconsidering the name of the new panel, however, because of concerns it could result in confusion with the similarly named RISC. | NERC
The collapse of the existing committee structures aims to save time and money and reduce the “silos” and inefficiencies that some NERC members believe the three existing committees have created over time.
Exelon’s Jennifer Sterling, vice chair of the Member Representatives Committee (MRC) and co-chair of the Stakeholder Engagement Team (SET) that made the proposal, led the webinar.
“The idea is that we pivot quickly and focus resources rapidly,” she explained in her opening remarks. “You are all aware that our world and our industry are changing quickly and that the pace only continues to accelerate. We need to be agile. We need to be readily deployed to address these emerging issues.”
Existing subcommittees and task forces would remain intact for the time being and report to the RSC. Subcommittees that do not have recurring tasks would be eliminated or combined with others. “The whole idea is that every subcommittee should understand what their task is,” Sterling said.
Reassurances
Sterling acknowledged some stakeholders have expressed fears that the overhaul could unintentionally eliminate networking, workshops, lessons-learned sessions and similar interactions that have developed over the years.
“That was never our intention,” she said. “We would expect that the [RSC] would continue those activities going forward.”
Sterling also addressed concerns that reducing the number of committee members would diminish transparency and stakeholder involvement. “We are committed to making sure the meetings are held in spaces that are open and that provide enough space for everyone who wishes to attend,” she said.
Potential Changes
Sterling also indicated NERC is considering potential changes to the plan based on stakeholder feedback.
The SET proposed a “hybrid” of the regional representation used by the CIPC, the sector-based membership of the PC and OC, and the at-large membership of the MRC and Reliability Issues Steering Committee (RISC).
The RSC would include one voting member from each sector (except for the regional entities), 20 at-large members, a chair and a vice chair. Members would be selected by a nominating committee of NERC officers and approved by the Board of Trustees, with selections based on interconnection diversity, subject matter expertise, and a mix of small and large entities.
“Let me emphasize the word ‘proposed’ here,” Sterling said in prefacing her description of the proposed RSC makeup.
“We have gotten a number of comments that perhaps people would like to see more sector representatives. Right now, we have one per sector, but people have asked for two. And also, there have been a number of comments that they would like to see the sectors elect their own representatives. … These will all be discussed at the upcoming [SET] meeting, and I’m sure it will be discussed next week at the MRC.”
Sterling said her team also has heard stakeholder concerns that the proposed timeline — which calls for nominating RSC members in the fourth quarter and completing the transition in the first quarter of 2020 — may be too aggressive.
Stakeholders also have expressed concern that the RSC’s name could cause confusion with the RISC. “Essentially, the RISC will be developing the lists of risks on a strategic basis,” Sterling explained. “That RISC report, along with other reports, would then be used by the RSC to develop their tactical work plans.
“There were some people who thought that name, the RSC, might be confusing,” she acknowledged. “So, we’ll talk about that as a group at our August meeting.”
Cost-benefit Analysis
Only two stakeholders had comments during the workshop. Barry Jones, of the Western Area Power Administration, asked why the plan did not include an “impact analysis.” Keen Resources’ Robert Blohm, a member of the OC, said the proposal might not produce the promised efficiencies.
“What we have now are three groups simultaneously dealing with three parts of the overall issue, saving a lot of time,” he said. “I would have been more comfortable seeing this [proposal presented in] a more objective or less presumptive fashion, where cost-benefit arguments, pro and con, are listed quite clearly.”
Sterling said the SET’s goal was achieving efficiency, “and hopefully cost savings will result.”
Mark Lauby, NERC chief reliability officer, said the revamping would increase NERC’s effectiveness at addressing issues in a holistic manner. “Going from 120, 130 people to whatever the size of this group ends up being, that will certainly be less of a burden and cost to industry,” he added.
Written Comments
The Policy Input Package for the August quarterly meetings includes written comments from 12 sets of stakeholders, including industrial consumers, cooperatives, generation owners, transmission owners, utilities and RTOs.
In addition to calling for an increase in sector representation, many of the commenters also recommended eliminating the requirement that RSC members have “executive leadership experience,” saying that subject matter expertise is more important.
The Canadian Electricity Association was among the most skeptical of the proposal. “While evolving reliability issues faced by the industry may require solutions and expertise that expand across traditional operating frameworks, many companies are still internally structured through a planning/operations/security model,” said CEA, which represents generators, transmission and distribution companies. “This reality may make it challenging to identify RSC members who can bring the necessary breadth of knowledge and experience to work across these industry areas.”
It also said issues addressed by the RSC must be “well-prioritized, while also guarding against dilution of attention due to a higher number of issues being overseen by one group rather than three.”
Several commenters said that while they agree with combining the OC and PC, they saw less synergy in combining them with the CIPC, which focuses on security.
The Electricity Consumers Resource Council (ELCON), which represents large energy consumers, recommended replacing the OC and PC while retaining a separate security committee. The ISO/RTO Council said that while “there is reasonable justification” for combining operations and planning, “including security matters in the combined group does not improve efficiency.”
The Cooperative Sector said its members were split on the restructuring. It was also critical of NERC’s transparency, saying some of its members “found it challenging to understand the deliberations of the SET meetings and that meeting notes/minutes were not provided to industry. Additionally, the proposal states that the current technical committee members were surveyed for input on the existing committee structure, but the survey results were not made public.”
Only one set of comments, from stakeholders representing state, municipal and transmission-dependent utilities, opposed the RSC proposal (Option 2) outright, saying they preferred Option 1: keeping the three committees and adding a steering committee above them.
“Option 1 provides oversight by refocusing the OC, PC and CIPC, while retaining the benefits those committees bring to NERC and the industry,” it said. “If it is not acceptable as a long-term solution, Option 1 should be adopted as the mechanism for achieving an effective and efficient transition.”
Most of the commenters called for a slower transition. Said ELCON: “Change management at this scale often takes about six months to complete.”
California must find new approaches to long-term forecasting and collaboration to keep pace with the accelerating effects of climate change on the state’s energy system.
That was the key takeaway from a California Energy Commission workshop Thursday focusing on developing strategies for climate adaptation in the state’s energy sector.
For California, adaptation is currently focused on the threat of wildfires and the role power lines can play in igniting them. The fire season is becoming longer in duration, increasingly destructive to natural and built environment, and more disruptive — and deadly — for the state’s inhabitants. (See California Regulators OK Utility Wildfire Plans.)
“The motivation behind this whole effort is really the stuff that we’ve seen in the news,” said David Saah, managing principal and co-founder of Spatial Informatics Group (SIG). “We’ve seen a bunch of extreme wildfire events that impact the grid, and as it impacts the grid, it impacts all of us in terms of costs, safety [and] reliability.”
Rim Fire | U.S. Department of Agriculture
SIG describes itself as an “environmental think tank” that combines spatial analytics with ecological, economic and social sciences to gauge the impact of policy decisions on ecosystems. The group is working with the state’s Cal-Adapt team to “deliver updated wildfire models for improved electric utility grid resiliency and safety” and support California’s next Climate Change Assessment.
Saah, an associate professor at the University of San Francisco and director of its geospatial analysis lab, explained that while much of the science behind wildfires is well understood, there are still a lot of “known unknowns,” including how to fit California’s recent large outbreaks of tree mortality into existing wildfire models to understand how “large, dead trees” affect wildfire behavior.
“We also know that our existing fire weather forecasts underestimate really severe or extreme wildfire events,” he said. “Part of that is due to the scaling; part of that is due to the technology; part of that is due to the way we have our measurements built. We know we need to deal with that.”
Saah said that current wildfire models do not forecast “a long-term trajectory of where we’re going” and therefore fail to provide investor-owned utilities a roadmap that can inform their long-term planning.
“And all this is really needed by not only the IOUs to be able to predict these overall impacts to the way they operate their systems, but it’s also needed by the taxpayer, the resident, the environment that we all have here in California,” he said.
But Saah said development of new models is not enough: Industry stakeholders must incorporate them into scenario planning.
“Our state is changing. We have this whole wildland-urban interface that we need to think of, and that interface is changing, and where it’s locating, it’s [also] growing. And the way fire behavior moves through those communities — again, it’s one of these places that we need to do better in.”
To address that shortcoming and others, SIG is developing a three-pronged approach to wildfire planning.
The first part seeks to improve the situational awareness of extreme fire weather and tree mortality through “optimal configuration” of weather stations, examination of past extreme events, and analysis and mapping of tree mortality. The second part incorporates new scientific findings into near-term forecasts and long-term projections, while the third would create models that provide IOUs and other stakeholders with “actionable information” applicable to the time scales contained in those forecasts and projections.
Once those models are developed, Saah said their “source code” should be opened to the industry and wider public for critical examination.
“The more critics that we can get hammering away at it, the more learning we can actually get,” he said.
Shifting Paradigms
California regulators have lauded San Diego Gas & Electric as a model for how the state’s utilities can prevent wildfires in their service areas. (See Calif. Regulators to Scrutinize De-energization.) The utility credits its extensive weather monitoring system for the fact that its service territory hasn’t experienced a major fire since 2007.
Brian D’Agostino, SDG&E’s director of fire science and climate adaptation, said the utility isn’t resting on its laurels. The utility is instead effectively rebuilding what was once the world’s largest utility weather network. (The state’s larger IOUs are now poised to surpass SDG&E’s network as part of their wildfire plans.)
San Diego Gas & Electric credits its intensive weather monitoring with preventing major wildfires since 2007. | SDG&E
SDG&E plans to expand its network from 177 weather stations to 225 by the end of next year, with a focus on new installations along the wildland-urban interface that can provide data every 10 seconds to support emergency operations. The new stations will be positioned to perform a new function: minimizing the customer impact of power safety power shutoffs (PSPS) undertaken during periods of high fire danger.
“It’s not just where we find the windiest areas or where this weather information will best improve our fire models, but a big part of it is we have to work with the electric engineers on the system for PSPS events,” D’Agostino said.
SDG&E has also synchronized its fire behavior models with census and building data to identify the highest-risk areas with respect to population density.
D’Agostino also pointed out that SDG&E is also incorporating its database of 455,000 trees into its fire behavior modeling systems in order to identify every tree that has the potential to hit a power line. The utility is also simulating more than 10 million fires every day to determine the risks to its entire system.
“There is a lot of room for improvement, as we’ve heard [from Saah], so we’re looking closely to continue to collaborate with the ongoing statewide projects,” D’Agostino said, expressing excitement at the “open source” nature of the effort.
Speaking during a Q&A session at the end of the workshop, CEC Commissioner Andrew McAllister noted his agency must perform 10-year forecasts to help guide development of the state’s energy system. Pointing out that the CEC increasingly relies on scenario modeling as the effects of climate change “happen more quickly than anticipated,” he asked D’Agostino how SDG&E is considering higher-than-expected temperature increases as it maps out its own long-term transmission and distribution investments.
D’Agostino said he couldn’t directly speak to the utility’s funding priorities, but that as the head of meteorology, he could point to what his department is doing differently, including adopting an approach of focusing on only the most recent years’ weather data — rather than a long historical time horizon — to predict future temperatures and weather patterns.
Another change had to do with load forecasting. D’Agostino explained that SDG&E’s peak loads have historically occurred during periods when the hot, dry Santa Ana winds blow off the desert to the east of Southern California’s population centers. But a new pattern has emerged over the last 10 years in which hot, humid air masses coming from the south are accompanied by unusually warm water currents.
“Last year, we didn’t set a new [peak] load, but our water temperature off San Diego was supposed to be about 68, 69 degrees, and it was close to 80 for almost three weeks in a row, which kept our nighttime temperatures [from] even coming down to what our normal daytime high was,” D’Agostino said. “And that went on for weeks last summer and caused a lot of challenges in operating the electric system. So, we’re seeing a new type of load.”
Reiterating the point about the speed at which climate change is occurring, CEC Vice Chair Janea Scott asked, “What kinds of things do we need to do in this space to make sure that we’re doing our best to keep up or even get out ahead of things?”
“We’re entering into this no-analog scenario,” Saah responded. “We have no idea how this thing’s going to work. If you look at the way our scientific infrastructure’s been built for a long time, it’s been built around competitive science. I think that era’s over. I think we really need to get into collaborative science. And the place where we learn from each other as quickly as we can, we [will] change things as quickly as we can.”
D’Agostino said he seconded that view: “Our ability to work with each other at this point is really going to help us move faster.”
OGE Energy on Thursday reported second-quarter earnings that beat Wall Street’s expectations and reflected economic growth in its service territory.
