The Long Island Power Authority is inching toward New York’s first offshore wind farm, which would supply 90 MW of electricity on a site off the eastern tip, said Mike Voltz, director of energy efficiency and renewables for PSEG-Long Island, which operates the power grid for LIPA. “We expect that power purchase agreement to go to the LIPA board of trustees in December for approval.”
David Mooney, director of the Strategic Energy Analysis Center at the National Renewable Energy Laboratory, discussed how New York could meet its 50% clean energy mandate. Because the current hydropower penetration of 20% is not expected to increase substantially, wind and solar would make up the remainder.
“There’s enough flexibility that exists in the system to be able to manage 30% penetration of wind and solar, and that’s without adding storage to manage variability,” he said.
Charles Fox, senior director of regulatory affairs and business development for fuel cell manufacturer Bloom Energy, praised New York’s level of sophistication in discussing clean energy policy. But he said the state needs to proceed with caution.
“The process of implementation is absolutely critical. We all want to get to the promise of Reforming the Energy Vision, but it’s important to do that to recognize that not only customers but financial institutions have entrenched business models that are going to need to change to finance projects. With companies that may have power purchase agreements in seven to 10 states, and when you suddenly change the rules in one of those places, it has a reverberating effect through just the law of unintended consequences.”
Richard Kauffman, Gov. Andrew Cuomo’s chairman of energy and finance for New York, took on critics of the zero-emission credit program, which would subsidize upstate nuclear plants to keep their carbon-free generation available for another 14 years.
“It would be great, as some critics would have us do, to say ‘let’s replace the nuclear plants with renewable energy. Let’s do that right now.’ It’s just not practical,” he said. “We cannot snap our fingers and have it done. We need to recognize the role nuclear will play in a transition to a renewable energy future, as no one has put forth a credible plan for cost- and time-effective replacement.”
Jim Muscato, a partner at the Young/Sommer law firm, which has represented wind developers for 15 years, said permitting has become more difficult as state agencies like the departments of Health and Transportation become involved.
“The totality of the siting process is that it will take about three years. One of the specific challenges is that the government does not speak with one voice. When getting through the preapplication process, we’ve had more government agencies get involved in the process than have ever been involved before. We’ve had 15 years successfully siting projects, but now we are working with agencies that had never been involved before.”
INDIANAPOLIS — After demonstrating the capabilities of its new 20-MW battery for five months, Indianapolis Power and Light says it’s time for it to get paid.
The energy storage system at its Harding Street Station here has been providing MISO with primary frequency response since May. But the company told FERC in an Oct. 21 complaint that the battery is “supporting the grid with no means for compensation for the services rendered” (EL17-8).
Interior of IP&L’s Harding Street facility | AES
The complaint asks FERC to compel MISO to update its energy storage definitions and compensation.
“Nothing [in the Tariff] exists to allow the battery to participate in the regulation market and be appropriately paid,” Lin Franks, IPL’s senior strategist for RTO, FERC and compliance initiatives, told RTO Insider in an interview. “We’re hoping FERC will see the wisdom in compensating automatic frequency control, injecting when frequency is too low and withdrawing when frequency is too high.”
IPL argues its battery should be paid instead of charged when “withdrawing [power] in response to a frequency deviation.”
Franks said IPL is not trying to be critical of MISO in making the filing. She pointed out that in 2009, when MISO opened its ancillary services market in accordance with FERC Order 888, the requirement did not include details on how fast-start resources recover costs.
“That was fine for back then, but now that we have a lithium ion battery in the MISO footprint, it’s no longer just and reasonable. What was just and reasonable in 2009 isn’t necessarily just and reasonable now,” she said.
Franks said creating proper definitions and a compensation mechanism is an “industry-wide kind of challenge.”
“Nobody is mad at anybody. It’s just time to make a change … and we don’t want this to get on the back burner,” Franks said.
The battery — consisting of eight 2.5-MW blocks — is using the interconnection facilities of two gas turbine generator units, which connect to the Harding Street South substation. (See FERC Approves 1st Storage GIA in MISO.)
Franks said settlement and dispatch for IPL’s lithium ion batteries are “vastly different” than for MISO’s current Type II storage energy and demand response resources. IPL claims MISO’s dispatch protocols are currently tailored to flywheel storage only.
MISO spokesperson Jay Hermacinski said the RTO is assessing its next steps before responding to the complaint.
“It is relevant to point out that at MISO and across the industry, there are numerous discussions at both the policy and technical levels to determine the most efficient and effective ways to integrate new technology, including storage, to the grid,” Hermacinski said.
He added that MISO has begun work on broader storage issues, starting with a stakeholder workshop in January and through its market roadmap process. He also said MISO staff will attend FERC’s technical conference on storage Wednesday (AD16-25). (See “FERC Calls Tech Conference on Storage,” Federal Briefs.)
MISO is currently considering including medium-term energy storage resources in its definition of DR resources. (See MISO Stakeholders Provide Ideas on Incorporating Storage.) IPL called the current stakeholder process “indeterminate” and asked for “tight time limits on any required MISO compliance filings.”
Franks insists that MISO should gather stakeholders to work on new storage definitions. “You really have to start all over. It’s a very time-consuming process,” she said.
IPL has committed to sharing “as much data as it practically can,” Franks said, to help explain the battery’s benefits.
In its filing, IPL suggested using PJM’s Regulation D payment factor as a provisional model until MISO can develop its own method for compensation.
IP&L’s Harding Street Facility exterior | DOE
PJM developed the regulation market payment after being approached by IPL parent company AES in 2009. AES’ Laurel Mountain facility in West Virginia — 98 MW of wind generation and 64 MW of integrated battery-based storage — has been providing PJM regulation service since October 2011.
The PJM payment mechanism is “certainly not going to be perfect for the MISO footprint,” Franks said. “But for the interim period, we’re suggesting that it is equitable and fair until MISO does its own body of work.”
Franks said working through the stakeholder process to incorporate a new storage definition and compensation into the Tariff would take about two to five years. She added that while IPL has a few ideas on what storage definitions might look like, it would rather reveal them in MISO’s stakeholder process.
“We prefer to share our data and testing and experience and work together to find a way that actually works to present to the stakeholders. No man is an island,” Franks said.
The Energy Storage Association lauded IPL’s move and urged FERC to take action to stop IPL from having to “operate the system in a suboptimal manner” and degrade the useful life of the battery.
“Without proper market structures that recognize the value delivered by energy storage systems, there is no way that the system can be dispatched cost-effectively. And without market signals that reflect the storage system’s operating parameters, the storage system could be unintentionally compromised or damaged,” the group said.
IPL’s complaint has attracted motions to intervene from American Municipal Power, Calpine, the Electric Power Supply Association, the Indiana Utility Regulatory Commission, Alliant Energy and the Coalition of MISO Transmission Customers and battery maker Alevo.
ALBANY, N.Y. — A coalition of environmental groups and clean energy developers on Thursday called for upgrades in New York’s transmission system at the Alliance for Clean Energy New York’s 10th Annual Conference.
“Today’s unique circumstances dictate that the rapid construction of new high-voltage transmission infrastructure should be an important component of the state’s strategy to meet its clean energy goals,” said ACE NY, the Sierra Club, Pace Energy and Climate Center, Environmental Advocates of New York and the Natural Resources Defense Council in a statement released at the conference.
“When we’re looking at transmission projects for the future, we need to see them through the 50% renewables lens,” ACE NY Executive Director Anne Reynolds said, referring to Gov. Andrew Cuomo’s State Energy Plan, which requires the state to procure 50% of its electricity from renewables by 2030.
The joint statement was also filed with the New York Public Service Commission, which is overseeing two transmission initiatives under the public policy provisions of FERC Order 1000. (See NYISO Identifies 10 Public Policy Tx Projects.)
The groups had a willing ally in NYISO CEO Brad Jones, who addressed the attendees at the morning session. He decried the 10- to 12-year process to get transmission built, advocating an expedited process of no more than six years.
“We need to develop our transmission system with an eye toward where renewables will be built,” Jones said. He said transmission developers need to build what he called a collector system, where renewables can be easily connected.
He said the ISO wants to lessen risks for energy developers who currently may seek less-than-optimal sites to access existing transmission; Jones had experience in Texas helping to develop collector systems in which networks of lower-capacity transmission lines would link several wind farms to a central point where they would connect to the main transmission corridors.
“My staff calls this our moon shot,” said Jones, who paraphrased President John F. Kennedy’s 1962 Rice University speech about landing a man on the moon: “We do it not because it is easy, but because it is hard.”
Reynolds said new lines should be built only if they help deploy wind and solar projects.
“With nearly 4,000 MW of new renewable energy projects proposed, real progress toward New York’s 50-by-30 goal is in sight,” Reynolds said in a statement. “New transmission capability is needed, but with upstate New York turning to a renewable energy future, the state should only be investing in those lines that are needed to deliver wind- and solar-generated power.”
WESTBOROUGH, Mass. — The challenge of preserving competitive markets while decarbonizing the New England economy was much on the minds of attendees at the Northeast Energy and Commerce Association’s 15th Power Markets Conference last week.
Some stakeholders fear New England states’ plans to procure up to 2,000 MW of renewable capacity could suppress prices in ISO-NE’s Forward Capacity Auctions. Those fears have receded somewhat, as the states are currently in negotiations for no more than 460 MW. (See New England States Move Toward Renewables Contracts.)
“The short-term problem isn’t as big as what was expected,” Jeff Bentz, director of analysis at the New England States Committee on Electricity, said during a panel discussion on the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) process. “That level is pretty small and could enter in FCA 12 [2021/22] but probably won’t enter until FCA 13 [2022/23].”
Another panelist, Peter Fuller, vice president of market and regulatory affairs at NRG Energy, described his company’s proposed two-step auction to accommodate state policy resources while maintaining efficient pricing for merchant generators.
The first auction would reflect the market without the effect of subsidized resources. which would be paid to all generating resources clearing in the first step. A second, lower price including the subsidized capacity would be paid to the generating resources that are subsidized by state policy.
All resources cleared in both steps would receive a capacity obligation, but these obligations would be pro-rated to ensure that the total quantity of generation purchased is no greater than the status quo, ‘merchant’ outcome. NRG says this would ensure that the cost impact of the states’ policy actions is shared among all market suppliers equitably.
“While NRG supports including state policy-subsidized generating resources in the markets, t wholesale sellers and the private investors in the market should not have to shoulder the entire burden of all of the state policy objectives,” Fuller said. “And effectively that’s the world we’re in right now. The [ISO-NE] renewable technology resource exemption, while limited, does create a price-suppression effect and potentially puts the full cost of adding those resources on the backs of all resources in the markets.”
Bill Berg, vice president of wholesale market development at Exelon, said the IMAPP meetings instead need to determine what subsidized resources are able to bid into the FCA and which aren’t. An estimated 8.7 GW of nameplate clean energy generation capacity will be needed to meet the states’ 2030 goals.
“We’re talking about 8.7 GW of subsidized capacity. Think about the angst that 200 MW has caused. Think about trying to design a market that puts both objectives, allowing the states to do what they want and protect reliability and the market, when you’re dealing with an 8.7-GW spread, which is 25% of the [FCA] market,” he said.
Pallas LeeVanSchaick, vice president of Potomac Economics, the ISO-NE External Market Monitor, said there are inherent risks in the adoption of out-of-market contracts intended to achieve public policy objectives.
“We’re going to get to the point that contracts with individual resources may not pass on costs in the short term, except that they’re able to fund those priorities through lower wholesale prices,” he said. “Maybe in the short term we don’t see higher rates to consumers, but in the long term, I bet we will see legacy costs that go on long after the impacts on the lower wholesale prices end. We’re going to notice over time that these are not in the interests of consumers.”
On a panel on the opportunities presented by energy storage, Ian Springsteel, director of U.S. regulatory strategy for National Grid, likened the industry to how consumers might have reacted to a smart phone a decade ago. It has seemingly unlimited potential, but the industry and public aren’t quite sure what the device can do or how to integrate it into daily practices.
“We’re in the same place with storage. We have an inkling of what it can do as one of many tools in the energy market or the distribution system. But to integrate it into all the rules and operational framework, to fully use this technology, we’re at the beginning of that process,” he said.
Christopher Parent, director of market development at ISO-NE, said the RTO is comfortable with storage, having had decades of experience with pumped hydro in New England. ISO-NE currently has about 90 MW of storage in its interconnection queue. The queue has a total of 10,000 MW of resources, many from flexible fast-start gas generators.
“When we look at our 2025 [projections], we’re looking at 4,400 MW of wind and about 3,300 MW of solar on the system,” Parent said. “That creates a lot of variability on the system that shows annual summer peaks of about 25,000 to 28,000 MW. That’s going to create a need for a lot of flexible resources on the system, be it storage or whatever technologies materialize in the coming years. The key thing in the market is to send the right price signals so we get the response we need.”
MISO has filed with FERC its proposal to implement a separate three-year forward capacity market with a downward-sloping demand curve for its retail-choice areas.
The nearly 1,700-page filing, submitted Nov. 1, creates Tariff Module E-3 and makes corresponding changes to modules A, D and E-1 (ER17-284). Jeff Bladen, MISO executive director of market services, said the RTO took pains to incorporate stakeholder advice into the proposal over the 20-month period since the initial issues statement.
“The proposal is a reflection of the breadth of advice we got throughout the process,” Bladen said during a conference call after the filing. “There are no surprises in what we filed this afternoon. … We look forward to the review process FERC will undertake.”
The filing came despite calls from some stakeholders for more discussion. Bladen said that although all stakeholders didn’t agree on MISO’s forward auction solution, virtually all stakeholders agree that a problem exists that needs to be corrected. Bladen pointed to the OMS-MISO Survey that found a possibility of a generation shortfall below the RTO’s minimum reserve margin requirement in 2018. (See OMS-MISO Survey: Generation Shortfall Possible.)
MISO’s plan is designed to “ensure conditions don’t deteriorate further,” Bladen said.
“It’s no secret that there has been difference in opinion about the preferred approach,” he said.
Bladen said the proposal is designed to provide equally valued capacity from both merchant generators and regulated utilities. An analysis from The Brattle Group has demonstrated that the proposal would ensure enough capacity to meet reserve margins.
MISO is requesting an effective date of March 1, 2017, the beginning of its implementation timeline for the 2018/19 planning year capacity auction. He would not speculate as to what the RTO might do if FERC doesn’t approve the changes by then. “There are many plausible ways FERC might act, so there are too many hypotheticals,” he said.
To respect state jurisdiction, the filing includes a prevailing state compensation mechanism modeled after one in PJM that will provide an alternative method for demonstrating long-term resource adequacy outside of the forward auction.
Under the mechanism, state regulators can facilitate settlements of compensation rates between their load-serving entities and suppliers outside of MISO’s processes. Authorities must notify MISO of the amount of demand under such agreements two months prior to the auction.
The California Public Utilities Commission is protesting FERC’s decision to allow Pacific Gas and Electric to include a 50-basis-point ISO participation adder in its 2017 transmission rates proposal.
The CPUC said that the commission’s ruling “ignores the need to demonstrate that an incentive must be ‘justified’ pursuant to [FERC] Order 679,” which allows transmission owners to collect the adder as motivation to join an RTO.
The Sacramento Municipal Utility District (SMUD) joined the CPUC’s request that the commission reconsider its Sept. 30 order granting the adder, which the CPUC contends will provide PG&E an annual $30 million “unjustified windfall” at the expense of its ratepayers (ER16-2320). As a transmission customer of CAISO, SMUD uses part of the PG&E system to serve its own load and is subject to any rate changes.
Pacific Gas & Electric Transmission Lines | PG&E
While the commission’s Sept. 30 order accepted and then suspended PG&E’s request for a 10.9% return on equity based on concerns that the proposed rate adjustment could produce “substantially excessive revenues,” it denied a CPUC request to disallow the incentive adder. (See FERC Sets PG&E Rate Increase Proposal for Talks.)
The CPUC argued that California law requires PG&E — as well as the state’s other investor-owned utilities — to maintain membership in CAISO, invalidating the need for a financial incentive. Furthermore, justification for the adder is the subject of an ongoing proceeding before the 9th U.S. Circuit Court of Appeals, the CPUC noted.
FERC countered in its September order that the court challenge “does not operate as a stay of the commission’s consideration” of the issues.
In its Oct. 31 rehearing request, the CPUC pointed out that the commission has granted the adder to nearly every utility that has asked for it since it was implemented almost 10 years ago — including PG&E. The PUC has four times sought rehearing on the issue, but in each instance it withdrew the requests as a condition of a settlement.
“Faced with rapidly escalating transmission access charges, with no end in sight, the CPUC, and the California ratepayers who the CPUC represents, can no longer afford to let the FERC orders, which grant unjustified ROE incentives to California utilities for doing something they are already required to do, go unchallenged,” the CPUC wrote.
The CPUC estimates that the adder has so far cost PG&E ratepayers $125 million.
SMUD previously disputed the appropriateness of the adder and questioned whether it furthers California or FERC objectives with respect to the cost-benefits of ISO membership for PG&E customers. Like the CPUC, SMUD asked the commission to defer action on the incentive until the 9th Circuit’s decision.
FERC has scheduled a Feb. 7-8, 2017, settlement conference to address PG&E’s 2017 rate proposal.
FERC on Tuesday cast shade on an attempt by environmentalists and solar proponents to block NorthWestern Energy from cutting the prices for solar qualifying facilities in Montana.
But the commission’s procedural ruling didn’t address the merits of complaints that Montana regulators are attempting to discourage solar developers — a claim it will address in a separate docket.
The complaints were filed in response to the Montana Public Service Commission’s 3-2 ruling in June to suspend NorthWestern’s tariff for solar QFs larger than 100 kW under the Public Utility Regulatory Policies Act pending an updated rate review.
The commission acted after the utility sought emergency action, saying it feared a “flood” of QF filings because the rate — set in 2013 at $53.14/MWh (off-peak) and $92.37/MWh (on-peak) — was now 35% above its avoided costs (Docket No. D2016.5.39).
The change put about 130 MW of planned solar facilities in Montana in limbo. While the commission said solar projects could negotiate rates with NorthWestern while the review is pending, developers say they have no leverage and would be forced to accept the utility’s avoided cost figure.
FERC dismissed a complaint by the Vote Solar Initiative and the Montana Environmental Information Center, saying the PSC is not subject to the general complaint jurisdiction under Section 306 of the Federal Power Act and that the plaintiffs had no standing to file a complaint seeking PURPA enforcement (EL16-117).
“The Montana commission is not an entity that, for purposes of enforcement, [FERC] may, by order, require to take or not take particular actions,” FERC said. “Additionally, Vote Solar is neither a QF nor an electric utility, and as such is not authorized to file a petition for enforcement pursuant to Section 210(h) of PURPA.”
Jenny Harbine, an attorney with Earthjustice, which represented the complainants, called the decision disappointing. “It limits the ability for advocacy groups — including consumer advocates as well as clean energy advocates — to raise issues before FERC that are critical to the future of clean energy development and consumer choice,” she said.
Second Case Pending
But Harbine said the groups would participate as intervenors in a PURPA enforcement petition filed last month by FLS Energy, a North Carolina-based solar developer.
FLS said the Montana PSC’s actions “precluded [it] from continuing with the development of 14 advanced-stage solar QFs” and faces the loss of more than $750,000 that it has invested (EL17-5). The company said the order eliminated NorthWestern’s only PURPA tariff allowing for fixed, long-term payments for solar, which it called an “essential element of a financeable” power purchase agreement.
FLS Solar’s Fairmont Solar Farm in Fairmont, NC | FLS Solar
The developer said the commission’s order — which followed a hearing in which only the utility gave testimony and was not subjected to cross examination — is intended to discourage the development of small solar QFs.
“The Montana PSC performed a back-of-the-envelope calculation and suspended the rates based on an initial conclusion (untested by discovery or opposing testimony),” FLS said.
It said the commissioners’ “hostility towards the goals of PURPA is evident from statements made by a majority of the commissioners” at hearings in the NorthWestern case and in an editorial by Commissioner Brad Johnson, who accused solar developers of using PURPA to finance projects, “cherry picking the states with the highest government-assured rate to do business in.”
“Simply put, it was well past time to put the rate on pause and update it again,” Johnson said, noting that the Montana Consumer Counsel supported NorthWestern’s request for the suspension.
Dissent
In his dissent, Commissioner Travis Kavulla accused his colleagues of flouting the commission’s procedures and precedents.
“The intervention deadline to the proceeding occurred only after a hearing on NorthWestern’s motion was held. Certain parties — or rather, quasi-parties, since the intervention deadline had not arrived — participated in that hearing, but the developers of the projects that would be compensated under the rate schedule did not,” wrote Kavulla, the current president of the National Association of Regulatory Utility Commissioners. “The hearing commenced with the purpose of taking ‘argument’ on NorthWestern’s motion. Then, as a surprise to those in attendance, counsel for NorthWestern alerted the commission that it also wished to offer evidence. No other quasi-party presented evidence at this hearing.”
On Wednesday, FERC granted Montana regulators’ request for more time to respond to the petition, extending the deadline until Nov. 17.
Other States
Utilities in other states also are trying to limit PURPA payouts. Idaho, for instance, has limited such solar QF contracts to two years only in a 2015 ruling. Duke Energy is contemplating a similar move against solar QF rates in North Carolina, according to Vote Solar.
American Electric Power CEO Nick Akins hardly sounded like someone whose company had just taken a $2.3 billion impairment Tuesday, telling investors and analysts he is “very happy with the strategic process” and that “conditions are in place that are conducive to us achieving our objectives.”
Akins’ comments came as he led a panel of AEP executives briefing investors and analysts in New York following the company’s third-quarter earnings release. With the one-time charge, AEP posted a loss of $765.8 million (-$1.56/share) for the quarter, compared with a profit of $518.3 million ($1.06/share) for 2015’s third quarter. Sales were up from $4.4 billion to $4.7 billion, partly because of a warm summer.
“The new story of AEP is one of higher growth, higher dividends, more regulation and more certainty,” Akins said. “When you stop chasing the wrong things, you give the right things the chance to catch you.”
Lower Rio Grande Valley Transmission Project | AEP
The impairment reflects AEP’s ownership share of 2,684 MW of competitive generation in Ohio, including its Cardinal, Conesville, Stuart and Zimmer plants. It also includes the competitive portion of the coal-fired Oklaunion Plant in West Texas, the Desert Sky and Trent Mesa wind farms, also in West Texas, and some coal-related properties.
Akins said the company will spend $17.3 billion in capital investments through 2019 — $9 billion on transmission — an increase of $4.3 billion from plans laid out last year through 2018. The company owns the largest transmission system in the U.S., with 40,000 miles of lines and more 765-kV extra-high voltage than all other transmission systems combined.
“We’re focusing the proceeds on the [transmission business] we find attractive,” said Akins, who noted AEP already accounts for 14% of the country’s transmission investment. “We’re able to invest in transmission in an order of magnitude not many others have. If you’re looking for a transmission company, AEP is certainly that. We’re well-positioned as a regulatory business.”
The company also plans to increase its renewables through long-term power purchase agreements. AEP expects to add 5,400 MW of wind energy and 3,400 MW of solar power through 2033.
| AEP
Investors didn’t respond positively to the news. AEP shares closed Wednesday at $62.61/share, down 77 cents (-1.21%) on the day.
AEP’s embrace of regulation also allows it to escape the problems it faces in Ohio’s competitive-generation market. Many of the company’s coal plants date back to the 1970s and earlier, making them underperformers against other power units. Coal resources accounted for 71% of AEP’s generation in 2005, but that figure is projected to drop to 47% next year.
“Fortunately, AEP’s balance sheet can withstand this impairment,” CFO Brian Tierney said. “Combined with other sales of generating assets, it puts the Ohio generation debacle behind us. We also have wires companies in the states with very attractive returns.”
Akins said AEP would continue working with legislators to restructure the Ohio market.
Both AEP and FirstEnergy attempted to get relief from the Public Utilities Commission of Ohio with what amounted to a subsidy request for their competitive generation. While what opponents called a “bailout” was approved by PUCO, FERC effectively scotched the deals, saying they needed to undergo a more stringent review.
AEP decided to work to get favorable reregulation legislation approved.
But FirstEnergy — which reported a $1.1 billion loss in the second quarter, much of it related to the closure of five coal-fired units — filed a modified request with PUCO seeking a $558 million-a-year rate stability rider for eight years.
In October, PUCO voted instead to give the company $204 million a year for only three years. FirstEnergy has until Nov. 11 to file for a rehearing on the order, which it called “disappointing.” (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)
The Seattle City Council authorized Seattle City Light to perform “a detailed analysis of costs, benefits and potential risks” of joining the Western Energy Imbalance Market (EIM) to inform the council’s decision on whether to approve the move.
González | Seattle.gov
The unanimous Oct. 31 vote came three weeks after council members Lorena González and Mike O’Brien voiced concern about the upfront costs of exploring membership, leading the council to defer a vote on entering an “exploratory phase” with the CAISO-run EIM. González had expressed concern that authorizing a study created an expectation that “we will invest and carry forward” with the market. (See EBA Speakers Ponder a Western RTO.) With its vote, the council is asking City Light to flesh out the findings of an EIM benefits study performed by consulting firm E3 that showed the utility could earn an additional $4 million to $23 million in yearly revenues from the market.
“City Light’s own evaluation of the E3 study identified a number of deficiencies that call the study’s revenue estimates into question,” González told RTO Insider after the meeting. “Furthermore, the cost estimates were based on those experienced by other utilities entering the market. I think it prudent for City Light to do its own assessment of the costs it is likely to incur.”
González said the council’s ordinance provides the utility with “the time and spending authority necessary to conduct a thorough gap analysis.”
“The council’s vote gives us the opportunity to further investigate participation in the EIM,” said Scott Thomsen, City Light’s senior strategic advisor in communications and public affairs. “This will involve more due diligence to get more details on the areas outlined in the [E3] report.”
Introduced in September, the original ordinance would have greenlit City Light’s membership in the EIM, but it was scaled back ahead of the council’s Oct. 10 meeting to require more analysis before a final decision.
As approved by the council, the ordinance includes a González-sponsored amendment requiring the city-owned utility to report its findings to the council’s Energy & Environment Committee by April 10, 2017.
“This amendment will allow the council to receive and review the results of this analysis within a reasonable timeframe and grant City Light sufficient time to conduct the analysis that is required,” González said.
She said that there are “significant risks that accompany [City Light’s] varying revenue projections,” which needed adequate time for the council to evaluate before the utility could enter “what would be a new line of business.”
With a generating portfolio heavy in hydroelectric resources, City Light stands to benefit from the EIM as an exporter of the flexible ramping capability needed to smooth out intermittent renewables.
The utility’s revenue estimates from the market are dependent in part on water supply conditions. Implementation is projected to ring in at about $8.8 million, while operations costs could run at around $2.8 million annually.
The Pacific Northwest’s ability to export power from surplus hydro can vary significantly based on precipitation.
“While there is a range in the estimated benefits, it is commensurate with the uncertainty in our current hydroelectric generation portfolio because of variable weather and water conditions,” City Light said in a summary and fiscal note to the council.
WILMINGTON, Del. — Still unable to reach consensus on the specifics of what to study, PJM members balked again last week at a request from a coalition of demand-side stakeholders to revisit the Capacity Performance construct.
By the end of the lengthy discussion at the Markets and Reliability Committee meeting Thursday, American Municipal Power’s Ed Tatum, who has represented the coalition in committee discussions, admitted he was at his wit’s end.
“I’m getting ready to curl up on the floor into a ball and roll around,” he said.
But even without the coalition’s initiative, stakeholders had plenty of capacity-related issues to discuss at last week’s MRC meeting, debating underperformance rules, seasonal capacity and pseudo-ties. They also began considering another look at ways to limit capacity auction arbitrage.
Tatum’s coalition continued to struggle with the scope of its proposed issue charge. The current issue charge suggests it is states’ public-policy actions that might upset the delicately balanced CP market. (See Review of PJM Capacity Market Put on Hold.)
However, John Farber of the Delaware Public Service Commission urged that the issue not be framed that way. “The existential threat is not with states, but possibly [to] customers who have to pay the eventual costs,” he said.
Some stakeholders pushed for adding more topics to those listed, while others said they opposed broadening the scope. Susan Bruce, an attorney who represents the PJM Industrial Customer Coalition, said the proposal needs to be broad enough to cover more than just capacity market impacts but narrow to the extent that PJMICC isn’t interested in talking about alternatives to RPM.
“I appreciate the dilemma,” she said.
EnerNOC’s Katie Guerry requested that the proposal’s language be more accommodating toward change rather than defensive. “Why don’t we set up a more productive process where we can work toward solutions?” she asked.
Both Bruce and Exelon’s Jason Barker said they would attempt to edit the proposal into something they could support, but “I’m not sure how to address that or to modify the current statement,” Barker conceded.
“What I’m hearing today is, ‘let’s re-broaden the discussion, at least to start.’ … I don’t understand what people want. Do they want to have a broad discussion and narrow it?” asked Jeff Whitehead, whose Direct Energy is a sponsor of the proposal. “It’s a pretty big ask of this group to have us find the right scope of this discussion before we start the work. One of the main issues here is defining what are these public policies that impact the wholesale market.”
Tatum said his goal is to find the CP version of the Serenity Prayer: a construct that can change what’s within its authority to change, accept what it can’t change and know the difference.
The lack of consensus caused frustration among the proposal’s sponsors. PJM’s Dave Anders, the committee’s secretary, suggested a separate informational meeting on the topic, but none of the sponsors actively supported the idea.
“I personally don’t see a need for an informational meeting,” said Steve Lieberman of Old Dominion Electric Cooperative. He said it would be “surprising” if there were new perspectives on the proposal than the ones that had already spoken up.
“Frankly, if we don’t want to talk about this, let’s stop talking about it,” Whitehead said.
Carl Johnson of the PJM Public Power Coalition, which also sponsored the proposal, reminded everyone that ignoring the issue wouldn’t make it go away. “If we don’t have this conversation, it’s going to happen without us,” he said.
Farber, who had registered the first concern with the proposal, nonetheless expressed support for it, saying the committee was “letting the perfect be the enemy of the good” and that he didn’t want to see it succumb to “paralysis by analysis.”
Stakeholders acknowledged that the current proposal was “substantially different” from past iterations. Tatum said he needed to confer with the coalition before deciding the next step.
Stakeholders not Quite Done with Seasonal Capacity
Stakeholders balked at PJM’s suggestion to sunset the Seasonal Capacity Resources Senior Task Force, saying there is more work to be done despite the RTO’s announcement Oct. 19 that its Board of Managers will file a “facilitated aggregation” proposal with FERC. (See PJM to Seek FERC OK for Seasonal Capacity Proposal.)
While stakeholders praised the job PJM’s Scott Baker has done steering the task force, they derided the RTO’s handling of the issue. PJM’s proposal was one of five voted on by the task force in September, but it received only 32% support.
CPower’s Bruce Campbell said he was “very disappointed in PJM’s actions in … pre-empting a viable discussion.” Guerry explained that the reason some stakeholders were upset is because the RTO’s action was contrary to stakeholders’ “expectation of the rules and how the process was supposed to play out.”
Barker, however, commended PJM’s leadership on the issue. “Let’s sunset it and move on,” he said.
Bruce suggested a “quick hibernation,” as when it announced the planned filing, PJM had noted that there were additional pieces of the structure to work out.
The indignation with PJM transitioned to the next discussion, in which Whitehead presented to the committee his proposal from the task force. His “substantive but simple” proposal would allow base capacity to participate in the auction for another year to allow enough time to fully consider the topic, he said.
“It’s our view that the board decision unfortunately wasn’t informed by some of these critical pieces of the stakeholder process,” he said.
Seasonal resource owners were only able to address the differences between forecasted peak loads in summer and winter “at kind of a cursory level,” he said. PJM has experienced colder periods than the 2014 polar vortex on which much of the capacity decision-making is based, he said. Its top winter peak-load day occurred in February 2015.
“I’m not sure it continues to make sense to continue to make reliability procurement decisions based on one year’s experience,” he said. “It doesn’t make a lot of sense that we would buy capacity to run somebody’s air conditioner in January.”
While Farber said the additional transition year was “critical,” Howard Haas of Monitoring Analytics, PJM’s Independent Market Monitor, objected to the proposed extension. Barker said the polar vortex highlighted issues that further investigation of a new seasonal-capacity construct might not address. “We need to be mindful of the nature of the winter constraints that we saw,” he said.
“I’m not disputing that this needs to be studied. That’s actually what I’m asking,” Whitehead said.
Later in the meeting, James Wilson of Wilson Energy Economics proposed a problem statement and issue charge to review PJM’s procedures for evaluating winter-capacity needs. “I don’t think it calls for a lot of changes, mainly just a few updates,” Wilson said. “It was really never much of a topic. … Winter capacity matters, we’ve learned.”
PJM’s Stu Bresler indicated that the FERC filing will likely occur prior to November’s MRC meeting. Because the task force sunset, the base capacity extension and the winter resource analysis proposals were presented as first reads, none will be voted on until that meeting — presumably after PJM has made its filing.
Underperformance Changes Would Weaken CP, Says PJM, Monitor
Asked to develop proposals for two CP issues, the Underperformance Risk Management Senior Task Force was only able to find consensus to endorse one.
The task force was charged with analyzing PJM’s pseudo-ties and flowgates to determine the impacts of integrating external CP resources. Of the four options proposed, the highest approval that any package reached was 38%. However, 78% preferred a change over the status quo.
PJM’s Rebecca Carroll said feedback is being collected from stakeholders through a new nonbinding poll, the results of which will be available this week. The group expects to review results and determine next steps at its Nov. 10 meeting.
The task force was also assigned to review underperformance rules. The endorsed package — which received nearly 55% approval — will be put up for a sector-weighted vote at the November MRC.
It would make several changes to Manual 18: PJM Capacity Market and Attachment DD of the Tariff including:
Basing the nonperformance penalty on the highest Base Residual Auction clearing price in any locational deliverability area instead of net cost of new entry;
Allowing underperforming units to find replacement megawatts from over-performing units in the same performance assessment hour area. Under current rules, such transfers are allowed only within the same capacity account with PJM;
Adding a new mechanism for transferring the replacement megawatts; and
Adjusting the stop-loss provision from annual to monthly.
Howard Haas of Monitoring Analytics, PJM’s Independent Market Monitor, was quick to register his objection to the proposal. “We think it’s going to weaken the product to the point where it no longer incents performance,” he said.
Others agreed, including Barker, PJM Public Power Coalition’s Johnson and the RTO itself.
“PJM cannot find itself in a position to support this package” Bresler said, explaining that it’s “too far down” the slope of not requiring CP units to perform at the exact time they’re needed, which the existing construct was specifically designed to do.
The proposal did have some champions, though, including Talen Energy’s Tom Hyzinski and John Horstmann of the Dayton Power and Light Company. Horstmann said adding a monthly stop-loss provides protections for the supplier and ultimately reliability because a monthly limit would provide generators with incentives to perform throughout the delivery year. Additionally, basing penalties on net CONE creates inconsistent penalty rates across differing LDAs, he said, and disproportionately penalizes the lowest-priced capacity with the highest percentage loss of revenue for a PAH penalty. Hyzinski said there are many other incentives to perform that keep the proposed changes from diluting CP.
Later in the meeting, Barry Trayers of CitiGroup Energy proposed another Manual 18 revision to eliminate a prohibition on how early a capacity obligation replacement can be made. Trayers’ proposal was followed by a friendly amendment from PJM that refined the language of the proposed rule change. The proposal will be brought back at November’s MRC for a vote. No one voiced any concerns about how the separate replacement changes would integrate.
Buy High, Sell Low?
Stakeholders would consider anew the price differences between the BRA and incremental auctions under a problem statement proposed by Whitehead.
Whitehead said the stark differences between the BRA clearing prices and the lower IA prices raises the potential for abuse. Noting that load is receiving cents on the dollar on excess capacity released by PJM in the later auctions, he proposed investigating whether IA prices yield reasonable and accurate results and revise policies if they don’t.
Citing results from recent auctions, Whitehead highlighted the disparity that creates an incentive to sell during the BRA and buy back during the IA at much lower prices.
Other stakeholders agreed. Calpine’s David “Scarp” Scarpignato said the structural issues between the two auctions “[create] a lot of speculation.”
For all but one delivery year between 2012/13 and 2016/17, the third IA auction clearing price has been a fraction — between 8 and 20% — of the BRA price.
The only time the IA price exceeded the BRA was 2015/16, when PJM did not sell back excess capacity in the IA.
Whitehead also noted that PJM’s excess sales have resulted in much larger reductions in the capacity acquired than in the cost savings to load. “In essence, load gets a lot less reliability in exchange for a negligible reduction in capacity cost,” the problem statement says. “Load should be appropriately compensated for the resulting reliability reduction, in consideration of the fact that, among other benefits, capacity in excess of the PJM’s planning targets can have value in a tail reliability event.”
Because prices in PJM’s Base Residual Auction are much higher than those for Incremental Auctions in which the RTO sells excess capacity, load has recognized little savings for the reliability benefits it has forgone. | PJM
The issue is not a new one. In 2013-14, stakeholders wrestled with ways to eliminate what some called “arbitrage opportunities” between the BRA and IAs. The effort ended in May 2014, after FERC rejected a plan to curb speculation in the auction, saying it created undue barriers to entry. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
The commission ordered a Section 206 proceeding and technical conference to explore the issue further (EL14-48) but did not schedule the conference after PJM asked the commission to defer action while it developed CP.
