FERC on Friday again rebuffed generators’ request to apply ISO-NE’s minimum offer price rule (MOPR) to 200 MW of renewable generation that were granted an exemption in 2014 (ER14-1639-005).
Although the order mainly rehashed old arguments, it offered Commissioner Norman Bay one last chance to blast the MOPR, which he did in a six-and-a-half-page concurrence.
The commission rejected a request by NextEra Energy Resources, Public Service Enterprise Group and NRG Energy that it rehear its April 2016 order upholding the exemption. The 2016 remand order came after the companies challenged the exemption in the D.C. Circuit Court of Appeals. (See FERC Affirms ISO-NE’s MOPR Exemption for Renewables.)
The commission reiterated expert testimony and economic theory that it said indicated the renewables exemption was necessary to protect consumers from paying for excess capacity and did not suppress capacity prices. It said the results of Forward Capacity Auctions 9 and 10 in 2015 and 2016 — as well as the qualifying filing for FCA 11 on Feb. 6 — “substantiate the reasonableness of the commission’s original determination.”
Bay, whose last day at FERC was Friday, used the order to offer a parting shot at MOPR.
“Despite the best intentions of the commission, in my view, the MOPR has turned out to be unsound in principle and unworkable in practice,” Bay wrote. “No other market in the United States is subject to the same construct in which a federal agency reviews state action and imposes an administrative price floor on supply offers from certain resources that have received state support. This places the commission in direct and recurring conflict with the states, ignores the pervasiveness of state and federal policies that support resources in one fashion or another, and represents a significant intervention in the market that raises costs to consumers.”
Bay appended a similar statement to another order on Friday that endorsed a MOPR exemption for demand response resources in NYISO capacity auctions.
FERC ruled last week that MISO’s Tariff unreasonably limits energy storage, directing the RTO to craft more inclusive Tariff language within 60 days.
The commission concluded Feb. 1 that MISO’s Tariff “unnecessarily restricts competition by preventing electric storage resources from providing all the services that they are technically capable of providing” (EL17-8).
While MISO includes stored energy resources in its regulation market, it does not allow them to participate in the capacity, energy, ramp capability and contingency reserve markets.
The order came in response to Indianapolis Power and Light’s Oct. 21 complaint that the 20-MW battery at its Harding Street Station was capable of performing as a load-modifying resource but that the MISO Tariff prevented its participation. The battery can deliver 5 MW for four continuous hours, according to IPL.
Harding Street Energy Storage | AES
MISO has until the beginning of April to make Tariff revisions that “accommodate the participation of all electric storage resources, regardless of the technology, in all MISO markets that they are technically capable of participating in, taking into account their unique physical and operational characteristics,” FERC said.
The RTO had asked for IPL’s complaint to be dismissed, saying it was working with stakeholders on new storage definitions. It also cited FERC’s Nov. 15 rulemaking that would require RTOs to remove barriers to entry (RM16-23, AD16-20). (See MISO Asks FERC to Dismiss IPL Storage Complaint.)
Storage NOPR
FERC said that while the commission’s final rule resulting from the Notice of Proposed Rulemaking could address IPL’s concerns, the company had nevertheless met its burden under Section 206 of the Federal Power Act to demonstrate that the existing Tariff is unjust. The commission also said the final rule from its storage NOPR could take precedence over MISO’s compliance filing.
“In the event that MISO’s Tariff revisions conflict with the required tariff revisions in any final rule resulting from the storage NOPR, MISO may be required to adjust its Tariff to align with the commission’s determinations in that final rule,” FERC explained.
The commission did not find merit in two other grievances contained in IPL’s complaint. The company argued that MISO should have a compensation mechanism for automatic frequency control; the company also claimed that MISO’s dispatch protocols are tailored to flywheel storage only. (See IPL Asks FERC to Force Update to MISO Storage Rules.)
Although FERC said it was aware of the Eastern Interconnection’s declining primary frequency response, it agreed with MISO that it is currently sufficient to meet reliability under NERC’s BAL-003-1 standard.
“We agree with Indianapolis Power that primary frequency response is a critical requirement for interconnected grid operations, and that the Eastern Interconnection has experienced a decline of primary frequency response as compared to historic values,” the commission said. It also said MISO was not discriminating against battery storage, as all other providers of primary frequency response are likewise uncompensated. IPL’s storage facility has been providing MISO with primary frequency response since May.
IPL claimed that MISO’s current storage resource offer parameters would significantly shorten its battery’s life because it would result in a “dispatch of its battery at half-capacity continuously for one hour and then send a negative signal for the following hour to charge.”
But the commission said IPL failed to prove that MISO’s dispatch instructions would harm the battery, saying it “failed to cite to any Tariff provisions or business practice manuals that support this claim.”
FERC said MISO has previously informed IPL that while the Tariff requires a regulation resource “to be available for 60 minutes to provide regulation service, the actual market clearing and deployment will not cause the resource to be charged for one hour and then be discharged for one hour.”
IPL Responds
Lin Franks, IPL’s senior strategist for RTO, FERC and compliance initiatives, said that while the commission’s order did not grant the company’s request to be paid for “essential” primary frequency response, the commission has already made frequency response service a condition of interconnection with the grid in last year’s RM16-6 rulemaking. Franks said she expected additional industry discussion on the topic as resource mixes shift further and battery benefits become more “universally understood.”
“Our hope is to bring awareness of both the benefits of lithium ion battery storage and [its] regulatory challenges,” she said.
Franks said IPL will continue to promote the benefits of battery storage. “Technological advances in this field happen rapidly [and] understanding benefits and the regulatory changes needed to realize all these benefits can take years,” she added.
FERC last week said it will give CAISO more time to address its concerns over intertie bidding at the borders of the Western Energy Imbalance Market (EIM).
The commission last June rejected the ISO’s proposal to prohibit EIM participants from implementing economic bidding at the market’s external interties until the ISO could develop “appropriate rules and procedures” to manage the transactions. (See FERC Order Prods CAISO to Allow EIM Intertie Bidding.)
While last year’s decision acknowledged that CAISO had “identified issues that warrant further evaluation,” the commission said the ISO had not “sufficiently described” those issues. “As an initial matter, we find it inappropriate for CAISO to include in its Tariff an indefinite placeholder,” the commission wrote, referring to the ISO’s failure to propose a timeline for resolving the issue.
No ‘Plug and Play’
CAISO is attempting to address the concerns of Western market participants outside the EIM who complain that the EIM has disrupted the bilateral transactions that still predominate in the WECC. | WECC
But the commission’s Jan. 31 order was sympathetic to the position of the ISO and other EIM participants, who have maintained that there is no “easy plug-and-play format” for intertie bidding that each participant could adapt to manage transactions at the borders of their balancing authority areas. Although the commission urged ISO officials to continue efforts to increase competition within the EIM, the order failed to impose a timeline for adopting new rules (ER16-1518).
“We’ll have to sit down with our legal counsel and decide how we’re going to respond to the order. … It looks like FERC was generally in agreement with how we proposed to proceed with these issues, which I think are reflective in our [2017 policy initiatives] roadmap as well,” Greg Cook, the ISO’s director of market and infrastructure policy, said during a Feb. 2 meeting of the EIM governing body.
The order comes three months after CAISO, EIM participants and Western power sector participants opposed to the prohibition hashed out their views at a technical conference convened by FERC. (See Foes Narrow Differences at FERC Summit on EIM Bidding.)
At the conference, Mark Rothleder, the ISO’s vice president of market quality and renewable integration, summed up the perspective of existing EIM participants: “We must be careful not to impose requirements that degrade the fundamental design elements of the Energy Imbalance Market that could ultimately unravel the benefits the Western market is experiencing.”
Commissioners appeared to be largely swayed by the ISO’s reservations about moving too quickly toward producing a solution.
“We recognize that implementation of bidding at the EIM external interties may pose challenges for CAISO and the EIM entities,” the commission said. “We encourage CAISO and the EIM entities to eliminate barriers to greater EIM participation and to provide opportunities for increased competition within the EIM.”
Scheduling Bilateral Transactions
The commission also recognized the grievances of the Western Power Trading Forum and others who say they’ve been experiencing challenges in scheduling bilateral transactions into the EIM area since the roll out of the market. They are seeking another form of participation not available in current CAISO and EIM member tariffs.
The Public Generating Pool, which represents 10 municipal utilities in Oregon and Washington, suggested CAISO create rules allowing its hydro-rich members — which control little transmission and have modest budgets — to have access to the market through resource aggregation and a system of “appropriate” administrative costs.
The Public Generating Pool — which represents 10 hydro-rich municipal utilities in Oregon and Washington — has suggested that CAISO amend its EIM rules to allow non-members to bid at the market’s borders for an “appropriate” administrative fee that falls short of the full membership cost. | Leaburg Dam photo courtesy of Eugene Water Electric Board
While the order directs FERC staff to monitor CAISO’s efforts on the issue and requires the ISO to provide updates, it largely leaves the ball in ISO’s court by not setting a specific deadline for the grid operator to develop a solution.
“We understand that these issues may not have simple solutions, and that CAISO has many stakeholder initiatives that it must prioritize in order to make the best use of its and its stakeholders’ limited resources,” the commission said.
Still, the commission was favorably impressed that the ISO included in its 2017 Draft Final Policy Initiatives Roadmap initiatives designed to address some of the concerns raise by those seeking broader access to the energy market.
Key among them: a proposal to better align EIM base schedules with bilateral schedules at the seams of the market.
“That was a clear issue that came out of the FERC technical conference — where being able to provide some kind of mechanism for those bilateral schedules to manage the congestion risk going into or through EIM areas was a very important issue for a lot of market participants,” Cook said.
The commission said “we appreciate CAISO’s efforts thus far to address these issues” and encouraged the ISO to work with energy market participants to find way to reduce barriers to market participation.
“We believe CAISO and its stakeholders are in the best position to work through these issues at this time,” the commission said.
FERC last week clarified that it would allow CAISO contracts for transferred frequency response service to include a provision recognizing that counterparties could fulfill the agreements based on an annual measure of performance rather than a case-by-case accounting of responses to frequency disturbance events.
In the same order, the commission rejected a rehearing request by the Western Power Trading Forum (WPTF) and NRG Energy that challenged the fairness of the process by which the contracts were procured (ER16-1483).
FERC last month approved ISO frequency response contracts with the Bonneville Power Authority and Seattle City Light, both of which were contingent on the outcome of the commission’s clarification. (See FERC Accepts CAISO Contracts for Imported Frequency Response.)
CAISO filed a request for clarification after the commission last September approved the ISO’s Tariff authority to procure transferred frequency response from another balancing authority area (BAA). The ISO sought the authority in an effort to comply with NERC reliability standard BAL-003-1.1, which requires all grid operators to carry enough capability to respond to a disturbance.
In that order, the commission stated that the CAISO contracts must result in a counterparty actually providing the ISO with frequency response service and not simply be “an arrangement for counterparties to transfer a regulatory obligation by means of bookkeeping entries.”
The ISO sought more clarity from the commission on that point, contending that contract counterparties could interpret the decision as requiring them to have a net actual interchange measure in response to every single frequency disturbance event.
“Such a requirement would make it virtually impossible for the CAISO to contract for transferred frequency response quantities because balancing authorities cannot assure such a measure in response to every disturbance event,” the ISO said in its request.
CAISO contended that the transferred frequency response performance of a counterparty BAA should not be tied to each disturbance because compliance with the NERC standard itself is not based on performance in connection with a single event.
Powerex, which also sought clarification on the order, backed the ISO, holding that a BAA is able to meet the BAL-003-1.1 obligation through a median measurement of performance across all identified disturbance events during a compliance year.
The commission agreed with those arguments, acknowledging that “NERC determined that the degree of variability in observed frequency response performance values limits the usefulness of imposing a single event-based compliance measure” on BAAs.
“In directing CAISO to revise its tariff to state that it ‘cannot claim on a compliance form that it has received, or that the counterparty has transferred, more frequency response performance than the counterparty has produced,’ the commission did not intend to require BAs to achieve a specific net actual interchange measure for each disturbance event to support transferred frequency response contracts,” the commission said.
The commission rejected the contention by WPTF and NRG that it acted “arbitrarily and capriciously” in determining that the product category of transferred frequency response — the notion of which was introduced by the BAL-003-1.1 standard — consists of both compliance reporting rights and the physical delivery of primary frequency response service.
Under the contracts, the commission noted, CAISO would be acquiring both the reporting rights and the frequency response service, which would act as an “insurance policy” for the ISO in meeting its obligation.
“Contrary to NRG and WPTF’s characterization of the Sept. 16 order as stating that ‘generators are incapable of bidding to provide a physical product to the CAISO,’ the Sept. 16 order determined that generators and BAs are differently situated due to the unique nature of BAs’ BAL-003-1.1 compliance obligations,” the commission said.
The commission said that NRG and WPTF’s argument that BAAs might be circumventing competition provisions set out in FERC Order 888 by bundling service from their generators into transferred frequency response was beyond the scope of the proceeding.
FERC also declined to entertain a WPTF proposal to increase the size of the frequency response market by allowing generators to compete, saying that the issue before the commission was to determine whether the proposed CAISO contracts are just and reasonable “and not whether the proposal is more or less reasonable than other proposed alternatives.”
CAISO late last year launched a stakeholder initiative to develop a market mechanism for acquiring primary frequency response service. (See CAISO Seeks Primary Frequency Response Market.)
Participants in the Western Energy Imbalance Market (EIM) should not rely on it to reduce their capacity requirements, a CAISO official cautioned last week.
Mark Rothleder, CAISO’s vice president for market quality and renewable integration, made the comment when probed on the issue during a Feb. 1 meeting of the EIM’s governing body.
Rothleder shared his views in response to a question by Dan Williams, CAISO markets analyst with Portland General Electric, which is slated to join the market in October. “We often hear about the interplay between planning capacity — to be able to stand alone as an EIM entity or as a balancing authority — versus what happens in real time in the optimization benefits that we get,” Williams said.
Williams wanted to learn more about how the EIM influences how existing participants view their long-term flexible resource needs as a model “for how the rest of us are starting to look at that as well.” “Flexible” resources are those equipped to respond to variability on the grid stemming from the uneven output of renewable generation.
Rothleder said the question comes up during the ISO’s own resource adequacy process at the California Public Utilities Commission: How does a utility value flexible capacity at the interties to the balancing authority area (BAA) and, more generally, from the EIM?
EIM’s Design
The answer lies in understanding how the EIM was designed and what it is intended to do, Rothleder said.
First: It’s a voluntary market.
Second: The market is built on the idea that each participant maintains responsibility for its own BAA, unlike in a full RTO.
“You put those two things together and I think you get to the point where the balancing area, in order to maintain their reliability, can’t rely on EIM to avoid capacity upgrades that they may need to meet their [integrated resource plan], resource adequacy or flexible capacity needs,” Rothleder said.
Any participant that leans too heavily on the market for reliability needs puts itself at risk because the market is oriented toward short-term resource sufficiency. The market penalizes those participants that come into an hour short of resources.
“If you fail those [short-term sufficiency] tests, you basically are isolated and you stand alone, and at that point you have to rely on your own flexibility and capacity,” Rothleder said. “You are not able to rely on the rest of the Energy Imbalance Market.”
Graph shows the frequency of flexible ramping sufficiency test failures for APS during the fourth quarter. Failure of the test ahead of an operating hour puts an EIM participant at risk of being isolated from the market during the interval, requiring it to draw on only its own resources to meet ramping needs. | CAISO
The EIM is designed to ensure that participants come into the market with adequate resources while benefiting from the economic efficiencies of intra-hour dispatch. “But you don’t necessarily get the benefit of avoiding long-term capacity,” Rothleder said.
EIM vs. ISO
That’s the difference between the EIM and full participation in the ISO. “Under full participation, those types of issues — long-term capacity, long-term resource adequacy — become subsumed under the umbrella of the footprint of the integrated balancing area,” Rothleder said. “Then you can deal with those things.”
Rothleder pointed out that studies quantifying the benefits of the EIM have addressed only short-term efficiency, not long-term capacity.
EIM governing body member Doug Howe pressed Rothleder on the issue. “You said the benefits of EIM don’t include the value of avoided capacity costs, but that’s not to say that there isn’t avoided capacity costs in the EIM,” Howe said. “Am I correct?”
Rothleder responded that getting credit for EIM-based capacity would come down to a “judgment call” between the participant and its state utility commission. And he also pointed to the risks of taking that approach.
“Do you now avoid getting flexible capacity in the area and setting up your own sufficiency?” Rothleder said. “Because if you do that, you run the increased risk of coming in short. And if you’re short, you’ve got to be able to manage those variabilities on your own.”
Governing body member Carl Linvill pointed out that EIM members have touted the market’s contribution to improving their own knowledge of their systems and ability to optimize processes. “It seems to me that speaks to some flexibility benefit associated with onboarding” with the EIM, Linvill said.
The improvements associated with transitioning from manual to the EIM’s automated dispatch would still be considered short-term benefits, Rothleder said.
Linvill asked whether EIM members could reduce their reserve margins after participating in the market over a period of time.
Reserve margins are generally tied to peak load, which doesn’t change with the EIM, Rothleder said.
“Can they factor in other things? Potentially,” he added. “But I think that becomes a real judgement call to rely on the EIM, so I can’t speak to that.”
CAISO CEO Steve Berberich said the issue pointed to the limitations of the EIM.
“This is one of the benefits of a fully integrated market: You get capacity benefits,” Berberich said. “You don’t get capacity benefits in the Energy Imbalance Market — and I’ll just leave it at that.”
It’s back to the drawing board for MISO, as FERC on Thursday rejected its proposed three-year forward capacity auction in its retail-choice areas, saying it would create too much price volatility and uncertainty.
The commission dismissed MISO’s 1,700-page proposal with an unusually short eight-page order — an apparent sign of its haste to rule before it loses a quorum with the resignation of Commissioner Norman Bay effective Feb. 3 (ER17-284).
The commission sided with MISO’s Independent Market Monitor, who opposed bifurcating the RTO’s capacity market by holding a forward capacity auction for competitive load three years prior to the current Planning Resource Auction.
A market-wide clearing process that operates within a single set of transmission capability constraints and supply offers is more efficient than a bifurcated capacity market, leading to better price formation, FERC said.
The commission also pointed out that a single market-wide auction is the current practice in all commission-jurisdictional capacity markets. MISO was attempting to single out its competitive retail areas, which account for less than 10% of total MISO load, FERC noted.
Volatility Concerns
The commission also said the three-year gap between forward auction and PRA could lead to “unpredictable and variable supply participation,” which could drive up price volatility in both auctions.
“Given the limited amount of demand that will be represented in the forward auction, relatively small changes in supply participation from noncompetitive retail areas on a year-to-year basis could result in substantial unnecessary year-to-year differences in forward auction clearing prices, even with a downward sloping demand curve that should reduce price volatility,” FERC said.
The introduction of a downward-sloping demand curve in the forward auction while preserving a vertical demand curve in the PRA also creates an inconsistent amount of capacity clearing in the forward auction and could intensify volatility in the PRA, FERC said.
It also said that MISO had not given enough thought to how transmission capability across zones and the MISO North-South contract path would be divided between the two auctions or how those allocations would impact clearing prices.
The commission noted that in MISO’s past prompt auctions, transmission capability constraints have caused significant price separation between zones. An insufficient amount of transmission capability in the PRA could prevent load-serving entities from procuring lower-cost capacity. A transmission shortage in the forward auction could cause price separation “that does not truly reflect the physical limitations of the system or the locational need for capacity,” FERC said.
“We appreciate the efforts of MISO and its stakeholders to address the important objective of resource adequacy and recognize that the [Competitive Retail Solution] proposal represents a significant undertaking. However … we find that MISO has not adequately supported” it, FERC said.
MISO Ponders Response
Richard Doying, MISO executive vice president of operations and corporate services, said that even though the order was a short read, staff continue to examine it. He said the RTO will approach its stakeholders for suggestions in the coming days.
“There are lots of smart people reading it and looking it over and over,” Doying told the Markets Committee of the Board of Directors during a Feb. 3 conference call. Doying also said MISO is not ruling out a request for rehearing.
Deputy General Counsel Eric Stephens said lack of a commission quorum moves MISO into “unchartered territory” with contested matters, which will be put on hold.
MISO’s proposal, filed Nov. 1, drew more than 40 comments and protests at the end of 2016 from critics, including the Monitor, which included in its protest a proposal for a two-stage prompt auction. (See MISO Forward Auction Filing Draws Protests.)
In a departure from normal practice, the commission did not provide a detailed description of — or response to — the protests.
“I think the FERC order is consistent with the concerns we raised, so we’re not unhappy with that, except that FERC didn’t provide any guidance,” Monitor David Patton said.
Patton said the commission’s lack of guidance in the order “creates uncertainty” and expressed disappointment that his two-stage prompt auction proposal was not addressed.
MISO spokesman Jay Hermacinski said the RTO’s effort to determine its next steps “will be complicated by the lack of detail” in the order concerning the reasons the proposal was rejected and the lack of guidance on how MISO can correct it.
“MISO appreciates the time and effort states and other stakeholders have already contributed to resource adequacy efforts in the MISO region,” he said in a statement Friday. “We will continue to work closely with them while seeking opportunities to gain guidance from the commission.”
Acting Chairman Cheryl LaFleur pledged to issue as many orders as possible before losing Bay, who announced his resignation after President Trump replaced him with LaFleur on Jan 26.
His resignation will leave the commission with only LaFleur and Commissioner Colette Honorable, one short of the three-person quorum required to act on major orders and rulemakings. The commission can continue to issue routine decisions under authority delegated to office directors. (See Backlog, Delays Feared as FERC Loses Quorum.)
WASHINGTON — Acting FERC Chairman Cheryl LaFleur on Thursday named David Morenoff as general counsel, replacing Max Minzner, a longtime associate of former Chairman Norman Bay.
The move restored Morenoff to the position he held during LaFleur’s previous stint as chair.
LaFleur also named Steven Wellner, her legal adviser since April 2014, as acting chief of staff. Jamie Simler, who had been Bay’s chief of staff, returned to her previous position as director of the Office of Energy Market Regulation in January.
LaFleur also named Terry Turpin as director of the Office of Energy Projects (OEP), effective Feb. 18, following the previously announced retirement of OEP Director Ann Miles. John Wood will succeed Turpin as the number two official in the office, but with an acting title.
The announcements were the latest dominoes to fall as a result of President Trump’s appointment of LaFleur as acting chair Jan. 26. The move prompted Bay to announce his resignation effective Feb. 3, a departure that will leave the commission short of the three members needed for a quorum. (See Backlog, Delays Feared as FERC Loses Quorum.)
Like Bay, Minzner decided to leave the commission rather than accept a demotion. LaFleur’s announcement said that Minzner had “decided to leave the agency to pursue other opportunities.”
Minzner met Bay while working as a law clerk at the U.S. Attorney’s Office in New Mexico about 20 years ago. Minzner was named general counsel in September 2015 after serving as Bay’s adviser and special counsel in 2009-10 when the latter headed FERC’s Office of Enforcement. (See Bay Replaces FERC General Counsel.)
Morenoff served as acting general counsel for nearly two years before LaFleur gave him the full title in August 2014. A graduate of Harvard Law School, he joined FERC from Troutman Sanders in 2006, after serving as a legislative aide to U.S. Sen. Jack Reed (D-R.I.). In addition to his work in the general counsel’s office, he also served as senior legal and policy advisor to former Chairman Jon Wellinghoff.
Wellner, a Georgetown University law graduate, joined FERC in 2012 from Dickstein Shapiro.
GDF SUEZ Energy Marketing will pay almost $82 million to settle market manipulation charges for offering generation below cost to capture make-whole payments in PJM.
FERC on Wednesday approved a consent agreement between the company and the commission’s Office of Enforcement that requires GDF to disgorge $40.8 million to PJM and pay a civil penalty of $41 million to the U.S. Treasury. GDF did not admit or deny the allegations (IN17-2).
The Troy Energy gas-fired plant in Luckey, Ohio, is one of the units GDF Suez used to own in PJM.
Enforcement charged GDF with violating the commission’s Anti-Manipulation Rule for an improper bidding strategy designed to increase its receipt of lost opportunity cost credits (LOCs).
According to the settlement, the Houston-based power marketer offered below-cost bids on some of its 12 natural gas-fired units to clear PJM’s day-ahead market and profit off the LOCs when the units weren’t dispatched in real time. GDF used a probabilistic, risk/reward approach to compare when units were unlikely to be dispatched against the risk of running the units at a loss, the settlement said.
GDF’s strategy was implemented between May 2011 and September 2013, when Enforcement questioned the practice. The scheme involved 12 simple cycle combustion turbines totaling 1,800 MW at four plants. Based on dispatch history, the company initially expected low energy margins from the units, which did not run often, and that their primary revenue source would be capacity payments.
GDF’s practice took advantage of PJM’s LOC rules, in which CTs that clear day-ahead auctions but aren’t dispatched are paid the difference of the real-time LMP and the higher of the unit’s price-based or cost-based energy offers. Because the formula didn’t subtract start-up and no-load costs, a generator with a day-ahead award could earn a greater margin when it received LOCs and was not dispatched by PJM in the real-time market than it would earn if it was dispatched.
GDF furthered its strategy by discounting its cost-based offers to the level of its price-based offers to ensure the units cleared the day-ahead auctions. The strategy also ensured that the LOCs it received would continue to be based on the discounted offer and would be higher than if based on the units’ estimated costs.
When the company expected that a unit would be dispatched in the real-time market, it typically offered the unit at or above cost and did not discount its day-ahead energy offer. It also typically offered uncommitted units that were not eligible for LOCs in the real-time market without discounting.
“As [GDF] gained experience in implementing the strategy, it became more aggressive in discounting offers for the CT units to get [day-ahead] awards in order to obtain LOCs, at times offering them with discounts as deep as -$25/MWh,” the settlement said.
The company has instituted additional compliance policies to prevent manipulative behavior in the future and will continue to conduct compliance training, the settlement said.
The company also submitted to monitoring and filing an annual compliance report. Enforcement can require a second annual report at its discretion. The compliance report must identify any known violations of commission regulations that happened during the reporting period and detail all compliance actions taken.
PJM’s payment is to be used at the RTO’s discretion — with Enforcement’s approval — to benefit its members.
The Western Energy Imbalance Market (EIM) saw total financial benefits grow 8% during the fourth quarter of 2016 with the addition of Arizona Public Service and Puget Sound Energy as participants, according to a report released by market operator CAISO.
The EIM generated gross benefits of $28.3 million during the quarter, up $2.1 million from the third quarter. The increase came despite typically lower electricity demand in the EIM area during the fall months, the ISO said.
The market has yielded $142.6 million in benefits for its members since being launched in November 2014, the ISO estimates.
EIM operations also helped to displace more than 10,000 metric tons of greenhouse gas emissions during the fourth quarter by enabling the dispatch of 23,390 MWh of surplus renewable energy output from California that would have otherwise been curtailed.
“That avoided curtailment is effectively being used to meet energy needs across the Energy Imbalance Market, and it basically is displacing emitting resources potentially elsewhere in the footprint,” Mark Rothleder, CAISO vice president of market quality and renewable integration, said during a Feb. 1 meeting of the EIM’s governing body.
Rothleder also said that the ISO predicts avoided curtailments to rise sharply with increased renewable energy production during late winter and spring this year. That seasonal pattern will be compounded by increased hydroelectric output stemming from an unusually high water year. The uptick in generation will coincide with low seasonal loads for California and the rest of West.
10-Year Peak for Hydro
Casey Cadle, a real-time operations shift manager for the ISO, said that California faces the heaviest hydro conditions in 10 years. “We’re also going to be having more solar than we’ve ever had in our system, so it’ll be an interesting time of year for us,” Cadle said.
The fourth quarter saw PacifiCorp realize almost $9 million in benefits, compared with $8.7 million for CAISO, $5.9 million for APS, $3.1 million for NV Energy and $1.6 million for PSE.
The benefits represent either cost savings — for example, the reduced need for reserves and greenhouse gas credits — or increased profits from merchant operations. The market’s ability to reduce curtailments also enables participants to collect renewable energy credits that would not otherwise be issued.
The benefits calculation nets out inter-balancing authority area (BAA) transfers that were scheduled ahead of the EIM’s 15- and five-minute market runs to avoid attributing contracted flows to the market.
Arizona ‘Freeway’
The report also showed that a significant amount of energy flowed from the PacifiCorp-East BAA into APS, and then again from APS into CAISO, suggesting that the Arizona utility’s transmission network is fulfilling its potential of becoming a major transit point between the interior West and California based on its ample transfer capability. (See Smooth EIM Transition for Arizona Public Service, Puget Sound Energy.)
“We can transfer a lot back and forth with PacifiCorp, NV Energy and the California ISO,” Justin Thompson, APS director of resource operations and trading, said last year after the company began operating in the market. “We’re kind of the freeway of the EIM system there.”
Rothleder noted that the prevailing transfers during the fourth quarter came out of PacifiCorp-East, with additional supply being picked up on parallel paths crossing Nevada and Arizona for delivery into California. Some flows continue north into the PacifiCorp-West BAA in Oregon.
The middle of the day often brings a reversal, as CAISO exports its excess supplies to inland areas.
“So there’s times where California is pushing and transferring back out to Arizona, to Nevada and on to [PacifiCorp-East], and that’s exactly how the Energy Imbalance Market is supposed to work,” Rothleder said.
CAISO says that transfers across BAAs are a significant contributor to EIM benefits because they provide participants access to lower-cost supplies, even when factoring in GHG compliance costs for energy imported into the ISO.
“The transfers are reflective of the economics and the system conditions at the time, and you’ll see this change and adapt as you change into different seasons,” Rothleder said.
FERC approved a formula rate requested by Transource Energy for its AP South Congestion Improvement Project, but suspended its implementation pending a hearing on whether the company’s proposed return on equity is reasonable (ER17-419).
PJM last year approved a $340.6 million proposal by Transource and Dominion High Voltage to address the congestion issue along the border of southwestern Pennsylvania and northwestern Maryland, despite criticism from other stakeholders. Transource’s part will include two 230-kV double-circuit lines about 42 miles in total: one between the Ringgold substation and a new Rice substation, and another between the Conastone substation and a new Furnace Run substation. (See FERC OKs Transource Pact on AP South Congestion Project.)
Transource, a joint venture of American Electric Power and Great Plains Energy, had requested a 10.4% base ROE, but protesters — including Old Dominion Electric Cooperative and American Municipal Power — argued that Transource incorrectly calculated the median of comparable rate proposals on which it based its request. The commission questioned the proposal as well and ordered an evidentiary hearing. The rate formula, including the approved ROE, will be effective Feb. 1.
The commission also rejected Transource’s proposed 50-basis-point “risks and challenges” adder, saying Transource “has not demonstrated that the project faces risks and challenges either not already accounted for in the applicant’s base ROE or addressed through risk-reducing incentives.”
The commission granted other requests, including a 50-point adder for RTO participation, 100% recovery if the project is abandoned, inclusion of the project under construction into the rate base and a hypothetical 60% equity/40% debt capital structure until the project is in service or secures permanent financing.
ODEC and AMP had protested the hypothetical structure, but Transource argued it was helpful for securing investors during a critical period for the project. Transource noted that it will likely have to negotiate for access to about 300 properties.
AP South is the first competitively awarded transmission project in Maryland and Pennsylvania, as well as the first competitive market efficiency project in PJM. The RTO expects it to produce approximately $620 million in congestion savings over 15 years. It’s expected to be in service by June 1, 2020.
The move restored Morenoff to the position he held during LaFleur’s previous stint as chair.
