Arizona Public Service can continue to charge market-based rates in Tucson Electric Power’s balancing authority area (BAA), FERC has ruled.
The commission said Jan. 30 that APS had overcome its concerns about the company’s ability to exercise market power in the neighboring BAA, closing the book on a Section 206 proceeding investigating the issue (ER10-2437-003).
APS said that closure of Unit 2 at its Cholla coal-fired plant contributed to the reduction of its market power in Tucson Electric Power’s service territory. | APS
The commission granted APS market-based rate authority (MBRA) despite finding “unpersuasive” the utility’s argument that it lacks the sufficient generation and transmission rights within the Tucson Electric area to exercise market power.
Commissioners also declined to rely on APS’s delivered price test (DPT) submission because the analysis did not cover all 10 required season and load periods.
“Because the indicative screens are only intended to screen out sellers that raise no horizontal market power concerns, we find that sellers opting to submit a DPT to rebut the presumption of market power must comprehensively analyze 10 season/load periods even if the indicative screen failure(s) only occurred in a single season,” the commission said.
Considered a more rigorous analysis than FERC’s “indicative” screens for determining market power, the DPT considers native load commitments to capture a detailed picture of an electricity supplier’s “available economic capacity” — energy available for offer in the open market — over multiple seasons and load conditions.
But other factors worked in the utility’s favor.
A key piece: Evidence included a supplemental indicative screen analysis showing that APS passed the pivotal supplier and wholesale market share tests for 2015 and 2016 — an improvement over the 2014 analysis that prompted FERC to institute the Section 206 proceeding.
The updated report showed APS’s summer period wholesale market share in the Tucson Electric BAA dropping from 22.4% in 2014 to 15.8% in 2015 — followed by another decline to 13.3% last year. The utility’s market share was well below 20% during other seasons and periods, the commission found.
APS cited as reasons for the reduction in market share Tucson Electric’s purchase of a portion of the Gila River natural gas-fired plant, the retirement of Unit 2 at APS’s Cholla coal-fired plant and the expiration of certain APS option contracts.
“Based on APS’s other alternative evidence, we find, on balance, after weighing all other relevant factors, that APS has rebutted the presumption of market power in the Tucson Electric balancing authority area,” the commission said.
The favorable ruling comes nearly six months after FERC rejected APS’s effort to gain MBRA in the Western Energy Imbalance Market (ER10-2437). In that order, the commission rejected the argument that CAISO’s mitigation measures would suffice to keep APS’s market power in check and noted that the utility did not even attempt to file indicative screens or a DPT to rebut the presumption that it exercised power within its own portion of the EIM.
The Jan. 30 decision also follows a November 2016 order in which the commission said that it would commence a Section 206 proceeding to determine whether Tucson Electric should retain MBRA within its own service territory (See Tucson Electric Could See Loss of Market Rate Authority in its BAA.)
That review was triggered after the utility filed a “change in status” notice demonstrating that it passed market share screens for neighboring BAAs but failed the same test for its own area (ER10-2564, et al.).
AUSTIN, Texas — ERCOT reliability unit commitment (RUC) activity increased more than three-fold in 2016, staff said at the Technical Advisory Committee meeting last week.
The number of instructed resource hours jumped from 411 in 2015 to 1,514 last year. Most of the activity occurred during the high-demand summer months, with almost 98% of the hours (1,481) noted as addressing congestion, primarily in the North and Houston zones, and the remaining 33 hours for capacity shortages.
No resource hours were committed for ancillary service shortages, voltage or reactive support, system inertia or in anticipation of extreme cold weather or startup failures.
“Although we saw a large increase in the total number of RUC commitments, we thought it was interesting to find the average dispatch limit and base points [metrics] stayed fairly similar,” said ERCOT’s Dave Maggio, manager of market analysis and validation.
According to Maggio’s report, 170 resource hours were dispatched above the low dispatch limit (a resource’s minimum production level in order to be dispatched). For 127.1 of those hours, the RUC-instructed resource was mitigated and the LMP was less than the RUC offer floor. He said the RUC-instructed resource was not mitigated for 39 hours and the LMP was less than the RUC offer floor, indicating a problem with its energy offer curve.
“If you remove the opt-out hours and just look at when the RUC occurred, it’s telling us that for 84% of the resource hours, the unit was never even dispatched off its [low sustained limit],” Barnes said, referring to a resource’s minimum sustained production capability. He painted Reliant Energy as not being in the “all-RUC-is-bad camp,” but in the “RUC-is-too-conservative” camp.
“In terms of what we’re getting for our money, [based on the results,] it’s arguable RUC didn’t always need it,” Barnes said. “If the unit was never needed to move 1 MW off its LSL [this often], we probably should be looking at the design of the RUC process. Is it too conservative or not?”
Potomac Economics’ Beth Garza, director of ERCOT’s Independent Market Monitoring group, pointed out to the TAC that 478 of the hours were bought back through the use of the resources’ opt-out status. Those resources are then excluded from RUC settlements as if the commitment never happened.
“There continues to be, from my perspective, great uncertainty in the market about how to opt out, and the specific process by which that can occur,” she said, reiterating what she called one of her “common themes.”
“It seems to me there’s a widespread lack of understanding of the specific actions that have to be done right now, versus after [NPRR] 744 is implemented. … The process will change.”
NPRR 744 was passed by the TAC and the Board of Director’s last spring and is scheduled to be implemented June 27-29. It is intended to improve the process used to notify ERCOT of a decision to opt out of a RUC order.
With the change, qualified scheduling entities (QSEs) that submit bids and offers on behalf of resource entities or load-serving entities will be required to opt out of RUC settlement by telemetering a resource’s status during the first interval it is online and available.
“This allows the entity that got RUCed to opt-out without using telemetry status,” Maggio said. The NPRR helps the ERCOT system, he said, “because the decision for employing the price adder [occurs] simultaneously.”
Noting about 600 of ERCOT’s RUC-committed resource hours took place in June and July, Garza said she believes much of that was a deferral by market participants in making their own commitment decisions.
“In deferring that decision, RUC is going to step in at some point and make a decision on your behalf,” she said. “To the extent we can get people to opt-out appropriately, there may not be a market impact. I think there’s a question there: Is [RUC] bad? Is it helping us get to better commitment decisions across the market? Opting out helps with that part as well.”
Several stakeholders pointed to the 33 resource hours instructed for capacity and questioned whether they should be in ERCOT’s market design.
“It’s created uncertainty around outcomes during those time periods that impact pricing during a capacity shortage,” said Citigroup Energy’s Eric Goff. “Hopefully, we have a significant price signal to get generators to commit themselves. If we don’t, that’s an even bigger problem.”
Morgan Stanley’s Clayton Greer suggested expanding ancillary services as another tool that could be used to “provide the same service.”
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week endorsed a protocol change that incorporates futures prices to estimate forward risk, a change that the ISO says could reduce market-wide collateral requirements by $30 million to $70 million, depending on several parameters.
Under Nodal Protocol Revision Request 800, collateral requirements would be calculated using a ratio of the futures average price to the historic average price. It would be based on the Intercontinental Exchange’s 21-day North Hub price curves.
ERCOT said exchange-based electricity futures market prices are “assumed” to be a better indicator of forward risk than historic ERCOT market prices.
Reliant Energy Retail Services’ Bill Barnes, representing the independent retail electric providers, called the change a “novel approach,” saying ERCOT may be the first electricity market to use this methodology.
“There is no better way to assess forward-price risk than to use the forwards, and that’s what this does,” he said. “It pulls those in and uses them to adjust your historical credit exposure.”
Barnes said the revision request represents two years of work by the Credit Working Group to improve how forward collateral evaluations are working in the protocols. ERCOT’s current methodology uses historical prices in its evaluations.
“In vetting [the current] approach, the working group found there were some pretty severe flaws in how they worked,” he said. “The most accurate way to collateralize future credit risk … [is] what do we think your participant represents as far as a credit risk to the ERCOT market.”
“It’s consistent with how we mark our exposure to the markets,” said Shell Energy North America’s Greg Thurnher. “It seems to make common sense. It seems to be more effective than our previous practices, which essentially look in arrears to anticipate a forward exposure when the seasonality of our market paints a very different picture.”
Luminant cast the lone dissenting vote, saying its opposition to the NPRR was based solely on the implementation costs to ERCOT and individual market participants.
“We estimate costs of up to $300,000 to make changes in our systems, and we don’t see the requisite benefit,” said Luminant’s Amanda Frazier.
Barnes noted the revision request was granted urgency status so that it could be incorporated into an existing release bundle for ERCOT’s credit monitoring and management system.
“That will potentially help streamline the implementation and perhaps lower the cost,” he said.
The change is estimated to cost ERCOT as much as $250,000 to implement. It has the support of the ISO’s Finance and Audit Committee.
Small Municipalities’ Revision Request Tabled for 7th Time
Tom Anson, an attorney representing the Small Public Power Group of Texas (SPPG), was granted a request to table until August his appeal of a rejected revision to the Nodal Operating Guide regarding the definition of transmission owners. This marks the seventh time NOGRR 149’s appeal has been tabled since it was first brought to the TAC last March, shortly after it failed to pass the Reliability and Operations Subcommittee.
The revision would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission operator services from a third-party provider if their annual peak is less than 25 MW. The NOGRR was developed in 2015 to settle the noncompliant status of seven municipally owned utilities, ranging in size from 9 to 21 MW.
Anson said the SPPG has been told it is “trying to make a market where there isn’t one,” and he said one transmission provider told the group it didn’t have “much of an appetite to provide service.” However, he also said the SPPG has four “conceptual” proposals in hand.
“These things take time,” Anson said. “We can’t promise we can turn any of these into a reality, but if the SPPG is willing to invest time and money into the effort with those who are helping them, we’ll see if we can’t turn one of these into not just a potential market solution, but a real market solution.”
Anson said the SPPG would withdraw its appeal should it reach a deal with one of the transmission service providers. He agreed to return to the TAC in May with an update.
ERCOT to Keep Admin Fee Flat Through 2019
Staff told stakeholders the ISO intends to maintain its system administration fee of 55.5 cents/MWh through 2019.
Market participants requested more advance notice of future fee increases during the 2016-17 budgeting process. The fee was raised from 46.5 cents/MWh during those discussions.
Committee Chairs, Vice Chairs Approved
The TAC confirmed its subcommittee leadership for 2017. The chairs and vice chairs are:
Commercial Operations Subcommittee: Chair Michelle Trenary, Tenaska Power Services; Vice Chair Heddie Lookadoo, Reliant Energy Retail Services.
Protocol Revision Subcommittee: Chair Martha Henson, Oncor Electric Delivery; Vice Chair Diana Coleman, Texas Office of Public Utility Counsel.
Reliability and Operations Subcommittee: Chair Alan Bern, Oncor; Vice Chair Boone Staples, Tenaska.
Wholesale Market Subcommittee: Chair Jeremy Carpenter, Tenaska; Vice Chair David Kee, CPS Energy.
Stakeholders Vote for More Inclusive Steady State Models
Stakeholders unanimously endorsed a revision to the Planning Guide that modifies the conditions proposed generating resources must meet to be included in steady state working group (SSWG) base cases (PGRR 053).
The change would require only the data provided for full interconnection studies (the standard generation interconnection agreement, applicable permits, notice to proceed and financial security) for including a proposed generation resource in the base case. ERCOT says the current rules, which also require completion of a resource asset registration form, has “created a need to unnecessarily use extraordinary dispatch conditions in the SSWG base cases.” The change will result in more representative generation dispatch scenarios in base cases, the ISO said.
“This lessens that data that’s required,” said ERCOT’s Jay Teixeira prior to including proposed All-Inclusive Generation Resources in the planning models. “Our intention was to pick up every resource that submits a resource form and are in the non-network model.”
The vote came after members struck references to “all-inclusive” generation resources, which had been added by the Reliability and Operations Subcommittee. Stakeholders said the term created confusion.
Katie Coleman, an attorney representing industrial customers, said she is working with ERCOT staff to update NPRR 190, which could help clear up the confusion. The NPRR was withdrawn in 2010 and was designed to add language acknowledging the existence of generation resources that qualify as distributed generation or are self-generators.
Revision Requests, Shadow-Price Cap Change Endorsed
The committee unanimously approved staff revisions to how ERCOT sets shadow-price caps and power-balance penalties under security constrained economic dispatch. The revisions update the shadow-price offer caps from $5,000/MWh to $9,000/MWh, reflecting the ISO’s current value for shadow-price caps.
The TAC also unanimously approved three additional NPRRs, another NOGRR and revisions to the Planning Guide. They will be brought to the Board of Directors on Feb. 14.
NPRR 794: Moves reporting requirements for unregistered distributed generation from the Commercial Operations Market Guide to the protocols. The NPRR was approved in conjunction with COPMGRR 044.
NPRR 805: Clarifies the criteria under which congestion revenue rights (CRRs) account holders can submit multi-month offers for long-term auctions. The months must be consecutive, within the period covered by the auction and during months when the account holder has ownership of the CRR.
NPRR 806: Clarifies that municipalities and cooperatives not participating in ERCOT’s competitive market (non-opt-in entities, or NOIEs) have the option of accepting a refund or capacity for their preassigned CRR-eligible resources. The NOIEs cannot select one option for some months of the year and the other option for the remaining months.
NOGRR 165: Aligns the operating guides with NERC reliability standards to ensure ERCOT and its transmission operators develop plans to mitigate operating emergencies. The plans should address NERC standard EOP-011 (Emergency Operations Planning) requirements and does not include black start or geomagnetic disturbance plans.
PGRR 052: Ensures appropriate operating limits are established when stability studies are performed after a full interconnection study (FIS) has been completed and model data or transmission system changes not available during the FIS become available before the new unit is brought online.
The resignation of former FERC Chairman Norman Bay means the agency will be unable to act on major orders and rulemakings for months, although it can continue to issue routine decisions under authority delegated to office directors.
Cheryl LaFleur is now Acting Chair of Federal Energy Regulatory Commission | FERC
Bay’s resignation, effective Friday, will leave the agency with just two members — one short of the three-member quorum. While the commission can continue to issue decisions on routine items such as uncontested market-based rate requests, extensions of time and compliance filings, many rulings will be held up until at least one more member is nominated and confirmed.
Bay announced his resignation within hours of the Trump administration’s naming of Commissioner Cheryl LaFleur as acting chair of the agency Thursday. (See related story, Bay Resigns after Trump Taps LaFleur as Acting FERC Chair.)
LaFleur said the commission would work to issue as many orders as possible while it still had a quorum. “I am confident that, with the strong team we have here at the commission, we can continue to do our important work,” LaFleur said in a statement Friday. “We are evaluating how best to do the business of the commission after Commissioner Bay’s departure.”
On Monday, the commission posted an 11-minute Q&A podcast with LaFleur in an attempt to reassure FERC employees and those who deal with the commission.
“We are very focused on the next week” during which the commission will still have a quorum, she said. “Beyond that, we have already confirmed that all of the existing staff delegations that are in place, including such actions as hydro inspections, LNG safety reviews, audits and all the other things that staff does, will continue during the period of non-quorum.”
She noted that staff issues five times as many orders as the commissioners do and said the commission is “thinking about potential expansion of staff’s delegated authority … basing that on past commission orders on the subject and the experience of other [federal] agencies.”
Procedural, Jurisdictional Issues
The commission’s website says “delegated” orders “may serve to determine a procedural matter in litigation. An order also may rule on a jurisdictional issue.”
Carolyn Elefant, a former FERC attorney advisor and lead partner at a D.C. law firm specializing in energy regulatory issues, agreed with LaFleur that much of the work coming out of FERC is done by staff and doesn’t need commission approval.
“Many of the commission’s day-to-day actions are handled through delegated authority to offices like Office of Energy Projects [and] Office of Enforcement,” she said. “The media picks up all of the contested actions, but the large majority of commission actions are routine approvals of uncontested market-based rate requests, extensions of time [and] compliance filings, which will continue as usual.”
But attorney Ken Irvin, co-leader of Sidley Austin’s global energy practice, said the loss of the quorum could mean that many rate filings become effective by default — decisions that he said cannot be appealed.
And law firm Baker Botts said it feared Bay’s departure could mean a growing backlog of cases. “Given the backlog of Trump administration nominees currently pending before the Senate, it could take several weeks or months for a new FERC commissioner to be nominated and confirmed,” said Jay Ryan, a partner in the firm’s D.C. office.
Ryan said the lack of a quorum will be problematic for the commission’s oversight and enforcement operations because it will be unable to issue orders approving audit findings, settlements of investigations and orders to show cause.
The Natural Gas Act and Federal Power Act require regulated companies to file rate and tariff changes 30 and 60 days, respectively, prior to their effective date, he noted. “If the FERC fails to act within the time that those rates go into effect, the changes become effective automatically, and if the FERC wishes to order further changes, it would have to do so under statutory provisions that place a heavier burden on the agency,” Ryan said. “Further, any requests for rehearing of the FERC’s orders under those statutes that are not acted upon by the FERC within a prescribed period are automatically denied.”
Another Baker Botts partner, Brooksany Barrowes, said the shorthanded commission also will be unable to approve any natural gas pipeline projects currently pending, though FERC staff can continue to prepare environmental documents and do other permitting work. “Given the need for expanded gas infrastructure and the narrow construction window many projects face, this could be a major issue,” she said.
CARMEL, Ind. — MISO’s effort to simplify treatment of behind-the-meter generation has created more questions than it has answered, stakeholders said last week at an educational meeting that turned into a contentious debate.
The RTO plans to split BTM resources into two categories for the purposes of market operations. The first would consist of “uppercase” generation described in the Tariff and dispatched in the market, usually as a load-modifying resource.
A second “lowercase” category would represent BTM resources not registered with or dispatchable by the RTO and not subject to market mitigation.
But some stakeholders expressed confusion over how the two definitions would address capacity deliverability or calculate network load for transmission billing.
The Jan. 26 debate is prompting MISO to re-examine its Tariff language and Business Practices Manuals with a promise for a more thorough discussion with stakeholders.
‘More Conversation’ Needed
“We’ve had some areas where more conversation needs to happen,” said Kim Sperry, MISO director of market engineering.
Stakeholders from multiple sectors said MISO does not have clear enough rules in place to require BTM generation to supply gross network load data before transmission rates are determined.
MISO staff said a legal precedent to provide gross load for transmission service for BTM generation was created 18 years ago in FERC Order 888, when the commission wrote that it “plainly require[d] inclusion in the rate denominator of ‘behind-the-meter’ loads” and said “load served by ‘behind-the-meter’ generation should be included in the load ratio share calculation for determining the transmission cost allocated to network customers.”
However, stakeholders wondered if that load calculation would apply to MISO’s lowercase BTM generation definition.
Sperry said she expected network load reporting to represent transmission losses for all BTM generation.
WEC Energy Group’s Chris Plante pointed out that there’s nothing in the Tariff that requires BTM asset owners to create gross loads to help determine transmission rates. Sperry said MISO would work with its attorneys to possibly create clearer Tariff language.
Stakeholders also said similar generators would be treated differently in terms of capacity deliverability, depending on their uppercase or lowercase status. In a previous meeting, stakeholders asked how BTM generation could be counted as deliverable capacity and how it can deliver when it exceeds local load. (See MISO Ponders Changes to Behind-the-Meter Generation Rules.)
MISO said that, as with other resources, market participants could either obtain firm transmission service from the BTM generator to the load or the generator could acquire network resource interconnection service (NRIS) through the interconnection queue and serve load to a network customer.
Those deliverability requirements amounted to a rule change three months ahead of the Planning Resource Auction, stakeholders said, contending that excess BTM generation has historically been sold into the market as capacity without requiring NRIS or firm transmission.
Not New Rules?
MISO staff maintained that the requirements were a “clarification” of what already exists in the Tariff.
“These are not new rules; these have existed in the Tariff,” said Neil Shah, system support resource planning manager. “These resources need to go through the same process as other resources.”
“As of now, that’s your opinion,” replied David Sapper of Customized Energy Solutions. “You’d better not try to enforce this without FERC approval. That’s my admonition.”
DeWayne Todd of Alcoa said MISO’s clarification could upend decades of practice in which BTM generators have delivered excess load for reliability purposes. Stakeholders asked how many megawatts of BTM generation would now be considered undeliverable.
“We need to go back and fill in the gaps on some definitions. That’s what I’m hearing,” Sperry said.
WPPI’s Steve Leovy said MISO should create a more detailed uppercase BTM generation definition, while others said the lowercase definition is too vague to fulfill transmission use pricing or capacity procedures.
Todd said the BTM deliverability requirement is infeasible because lowercase BTM generation would be ineligible for firm or point-to-point transmission service; those resources would not be captured in MISO’s Open Access Same Time Information System (OASIS), which provides data on available transmission capability.
“Why wouldn’t people just take all of their generation behind the meter and forego operating procedure?” American Electric Power’s Kent Feliks asked, referring to non-dispatchable BTM generation.
That was a question for MISO’s Resource Adequacy Subcommittee, the RTO’s Manager of Resource Adequacy John Harmon said.
“There are operation questions,” We Energies’ Tony Jankowski said. “Who gets to deploy that [BTM] resource? … We end up with a laundry list of questions and maybe stakeholders [should] work on these topics in other forums and come back.”
The Human Resources Committee of MISO’s Board of Directors is considering a 2016 executive incentive plan that would slash potential bonuses by more than 30%.
During a Jan. 24 conference call, the committee suggested MISO executives receive 68.5% of a possible discretionary bonus for last year because of incomplete queue reform, a failure to implement seasonal and locational aspects into the Planning Resource Auction, capital budget overspending and a market funding efficiency rating that showed room for improvement.
According to MISO’s 2015 Form 990 filing, incentives outpace base salary for the RTO’s three highest paid executives.
CEO John Bear was the most highly compensated, taking in a $709,872 base salary and $1.1 million in incentives. Executive Vice President of Transmission and Technology Clair Moeller came in second with a salary of $363,189 and incentives worth $401,131.
Stephen Kozey, senior vice president of compliance services and one of MISO’s original employees, earned $362,681 in salary and $372,888 in bonuses. Other vice presidents earned an average of $503,000 and $157,000 in incentives.
MISO spent $143 million on salaries, compensation and benefits in 2015, compared with $130 million a year earlier.
The RTO currently charges a $0.34/MWh administrative rate, which covers salaries and benefits in addition to fees for third-party consultants and computer services.
Greg Powell, MISO vice president of human resources, said that despite a shortfall that cut into bonuses, MISO’s market funding efficiency score of 95.8% demonstrated the best performance to date. The RTO defines market funding efficiency as the alignment between financial transmission rights, the day-ahead market and the real-time market.
Bear said MISO could have done a better job forecasting capital spending last year, with the RTO overspending its $31 million budget by $2 million. In comparison, MISO overran its $225 million operating budget by $2.2 million.
MISO was also unable to implement interconnection queue reform and seasonal and locational constructs for the 2017/18 PRA during 2016.
Bear thought the stakeholder process was sufficient, but he acknowledged that MISO could work more with its Independent Market Monitor’s recommendations.
However, the RTO gave itself an “excellent” rating for meeting all NERC reliability standards in 2016. Bear said that directors must typically discuss NERC reliability compliance performance in a closed session, but there was no need to do so because MISO had not committed a single violation in the year.
“I think it’s a really good accomplishment for us, and now the challenge is to maintain that excellence,” Bear said.
The 2016 MISO customer survey earned the RTO a threshold performance rating, with 82% of member respondents providing an average rating of five or better on a seven-point scale. MISO needed a minimum 80% to allow for the bonus payments.
“We have struggled mightily with metrics that are challenging,” Bonavia said. “We wanted it to be so that mid-level performance is a strong target, and we’ve seem to come out pretty well this year.”
Kozey said committee suggestions to increase or decrease the incentive package are historically made after closed session discussions.
FERC on Friday approved a NYISO plan to protect consumers from rising capacity prices in southeastern New York but rejected a one-year transition to the new rules, saying it “lacks analytical basis” (ER17-446).
NYISO proposed the plan in the fall to address anticipated price spikes in the capacity market in the Lower Hudson Valley and New York City zones, expected after the commission in October allowed the export of electricity from a New York plant in a constrained zone into ISO-NE. (See FERC Sides with ISO-NE in Capacity Dispute with NYISO.)
The ISO’s current capacity market rules fail to recognize the impact of counterflows: They assume that 100% of a generator’s exports from an import-constrained area must be replaced with generation in that locality. NYISO Market Monitor Potomac Economics warned the anomaly means capacity clearing prices in the Lower Hudson Valley “could rise far above competitive levels.”
In response, the ISO proposed a “locality exchange factor,” based on power flow analyses, which found that 47.8% of the capacity exported to ISO-NE from New York’s G-J zones could be expected to be replaced by capacity in the rest of the state. That meant only the remaining 52.2% would need to be replaced by capacity within the zones. NYISO’s proposal was vehemently opposed by generators, who said it would suppress prices. (See NYISO Board Denies Generators’ Appeal on Capacity Cap.)
FERC’s order approved NYISO’s methodology but rejected its proposal for a one-year transition to the new rules (June 2017 through May 2018), during which the ISO planned to use an 80% locality exchange factor rather than the 47.8% figure.
NYISO said the transition was proposed by stakeholders and received votes in support from four out of the five voting sectors. But the commission said there was no “analytical basis” for the 80% factor.
“In its proposal for the locality exchange factor methodology, NYISO states that ‘the price signal should reflect only the portion of the export that must be replaced by resources located within the locality.’ The one-year transition mechanism, however, is not based off of the same power flow analysis that NYISO argues is the best way of accounting for counterflows,” the commission said.
FERC dismissed supporters’ argument that the ISO needed more time to refine and evaluate the methodology. “If NYISO or, in turn, the commission, had some basis to doubt the efficacy of the locality exchange factor methodology, then rather than implementing a transition, the commission would be required to reject the methodology in its entirety as unjust and unreasonable,” it said.
FERC ordered a new plan submitted within 30 days.
Roseton | Google
The methodology was prompted by the commission’s October order allowing Castleton Commodities International’s 1,242-MW Roseton 1 generator, located 43 miles north of New York City, to export 511 MW of its capacity to ISO-NE beginning next June for the 2017/18 delivery year. If Roseton decides to participate in ISO-NE’s 2017/18 commitment period, NYISO would procure unnecessary replacement capacity, as Roseton would still be providing reliability services for the G-J zone, the ISO argued.
December was marked by all-time high wind output in MISO, along with higher gas prices and erratic weather patterns that challenged the RTO’s forecasters, officials said at a Jan. 24 Informational Forum.
Jeff Bladen, MISO’s executive director of market design, said that while average temperatures in December were “near normal,” the month saw “rapid transitions in temperatures and winds,” leading to inaccurate forecasting and poor unit commitment.
“Ultimately, unit commitment decisions are heavily influenced by weather forecast accuracy,” Bladen said.
There are ongoing efforts to improve load forecasting capabilities, he added. “The challenge is more volatile weather … it’s something we continue to work on to improve our ability to manage and predict,” Bladen said.
Load averaged around 77 GW during December, a 9-GW increase over November. The month’s peak of 100 GW occurred Dec. 19.
MISO’s systemwide energy prices averaged just above $30/MWh, up 22% compared with the previous month. Bladen said the increase could be attributed to an $3.59/MMBtu average natural gas price that was $1.15 higher than in November.
A month-to-month upending of wind output records has become almost standard for MISO, and a new high of 13.7 GW was set Dec.7, surpassing the previous record of 13.3 GW set in late November. Wind production for the month totaled 5,687 GWh, the highest value recorded for the RTO.
MISO Creates Focus Group for IT Refresh
MISO will create a Market System User Experience Focus Group to learn about information technology shortcomings, said Curtis Reister, the RTO’s director of software delivery.
The group will meet Feb. 23 and is open to all users of MISO market systems who would like to comment on their market experiences and make suggestions.
The group, part of MISO’s wider effort to make software improvements in 2017, will gauge customer satisfaction with usability, performance and security and seek to understand customer experiences. (See MISO to Study Aging Software; Market Improvements Planned for 2017.)
The RTO noted that its electronic market systems are more than 10 years old. While some applications have been improved for functionality, there have been “minimal” changes to front-end design.
“There is some dissatisfaction out there, and we want to understand it,” Reister said.
The focus group will also decide which IT investments will have the biggest payback, he added.
MISO CEO John Bear said software investments are needed to manage a larger, more diverse fleet. “We’re dealing with a lot more intermittency and a lot more generators,” he said.
Some of the improvements might require members to make system changes implemented over the long-term in order to give those members adequate time to update, Bear said.
MISO will also switch platforms for its external website, according to Executive Director of External Affairs Kari Bennett.
Stakeholder Input Needed on Cost Allocation
Patrick Brown, manager of transmission planning for MISO South, said the RTO expects stakeholders to submit comments on transmission cost allocation by Feb. 27, in time for a Hot Topic discussion at the March 22 Advisory Committee meeting.
The RTO released a market efficiency project (MEP) cost allocation strawman in December, proposing to lower the current 345-kV voltage threshold and remove a footprint-wide postage stamp allocation of costs in favor of one in which costs are borne solely by participants in benefiting transmission pricing zones. (See MISO Stakeholders Propose Changes to Market Efficiency Cost Allocation Process.)
MISO expects cost allocation refinement to continue into the third quarter before Tariff changes are drafted in the fourth quarter and filed sometime in mid-2018.
In a sprawling decision, FERC last week rejected requests for rehearing by multiple energy sellers implicated in market manipulation during the Western Energy Crisis of 2000/01 (EL00-95-289).
The sellers — which include Hafslund Energy Trading, Illinova Energy Partners, MPS Merchant Services, Shell Energy North America and APX — had asked the commission to reconsider previous findings related to the disgorgement of overcharges the companies raked in from May to October 2000, the so-called “Summer Period” of the crisis, which ultimately cost California ratepayers billions of dollars.
In that decision, the commission set out what it deemed the “appropriate remedy” for the anomalous bidding, false export and false load scheduling tariff violations engaged in by the companies in an effort to drive up market clearing prices during the crisis: the disgorgement of any payments received in excess of a marginal cost-based proxy price.
The commission decision dealt with companies implicated in manipulating prices during the initial “Summer Period” of the Western Energy Crisis.
A subsequent opinion required that companies found to have engaged in those practices would be forced to disgorge overcharges for all sales made during trading intervals in which market prices were affected by any of the companies’ tariff violations.
FERC dismissed as moot rehearing requests by MPS, Illinova, Hafslund and Shell that called into question the commission’s previous findings of tariff violations by the companies. The commission pointed out that the 9th U.S. Circuit Court of Appeals had already determined that FERC’s orders on those matters were final and that the commission “reasonably concluded that the sellers engaged during the Summer Period in the practices deemed tariff violations.”
The commission also denied a request for rehearing by MPS and Illinova in which the two companies contended that FERC’s requirement that an individual seller disgorge profits not directly connected to any violation they committed represents an award of retroactive refunds to buyers rather than disgorgement. The two companies had complained that FERC’s disgorgement remedy is limited to the return of profits obtained illegally. The commission countered that the 9th Circuit has recognized that the Federal Power Act “gives FERC authority to order refunds if it finds violations of the filed tariff and imposes no temporal limitations.”
FERC rejected an argument by all five companies challenging the validity of the marginal cost-based proxy price methodology being used in the proceeding. “The commission has affirmed the presiding judge’s finding that the marginal cost-based proxy methodology … provides for a credible proxy of prices in a normal competitive environment,” the commission wrote.
The commission also rebuffed the companies’ argument that they should not be responsible for disgorgement of profits from all sales affected by the tariff violations by any of the market’s participants. Commissioners said they found persuasive the arguments of a California expert witness that the tariff violations had “intertemporal” effects on the state’s market during the crisis.
The commission also rejected a contention by MPS and Illinova that the prices established by the CAISO and now-defunct California Power Exchange markets were contract rates subject to the public interest standard of review embedded in FERC’s landmark Mobile-Sierra decision.
“The prices set by the CAISO and CalPX auction markets do not constitute contract rates because they result from a generally applicable auction mechanism set forth via tariff,” rather than from an arms-length transaction between two parties, the commission said.
The CAISO and CalPX tariffs did not contain the terms of a public interest standard of review, the commission noted.
The commission also denied a request by Exelon, the successor-in-interest to AES NewEnergy, for a rehearing on the issue of the fuel costs the company submitted to offset its refund amounts.
“The commission considered the full array of evidence, noting certain CAISO records submitted by Exelon related to the transaction, but ultimately finding that Exelon had not ‘clearly linked any evidence of its actual incurred costs to the resource and sale at hand,’” the commission said, citing language in a previous ruling. The commission reiterated a requirement that fuel cost information be “clearly linked” with a resource and an energy sale and “easily verifiable by supporting evidence.”
Settlement Agreements
In two other orders stemming from the energy crisis, FERC rejected two of California’s motions to preserve remedies or refunds against other non-settling parties as a condition for concluding settlement agreements with Illinova and MPS (EL00-95-299, EL00-95-300).
California had asked for the commission to affirm that a settlement with either company would not release non-settling parties from facing the possibility of having to disgorge profits from energy sales inflated by tariff violations committed by Illinova and MPS. The state argued that FERC’s failure to grant the motion would make future settlements impossible by reducing the liability of the remaining sellers and incent them to wait for others to settle first, thereby deterring California from settling with any of them.
In denying California’s motion, the commission stated that it “has dismissed from the proceeding parties that settled … before and during the instant proceeding, excluded the conduct of non-parties from the scope of the proceeding and emphasized that the trading hours impacted by the settled parties’ tariff violations will not be included in disgorgement amounts due from the remaining respondents.” The state failed to provide a compelling reason for the commission to reverse that long-standing practice, the commission added.
The commission noted that it was not ruling on either settlement agreement and directed California to notify FERC within 30 days whether it wished to revise or withdraw from the agreements.
CARMEL, Ind. — MISO’s Steering Committee last week advanced three topics for discussion: the RTO’s settlement with SPP, a potential cost recovery defect and potential cost-sharing for customer-funded upgrades.
The committee decided that the Market Subcommittee will discuss a possible cost recovery gap, an issue raised by Entergy. The gap arises when MISO decommits or manually redispatches a resource to offline status, the utility contends.
“If the resource is later brought back online to fulfill the remainder of an existing commitment period or to meet a subsequent commitment period, the resource is not guaranteed start-up cost recovery,” Entergy said.
The company wants the RTO’s Tariff revised “to provide incentive for resources to follow MISO instructions and to ensure that a resource owner is not forced to choose between following MISO instructions and incurring an uncompensated cost, and disregarding MISO instructions.”
A discussion on generator-funded upgrades that benefit other interconnection customers was assigned to MISO’s Regional Expansion Criteria and Benefits Working Group (RECBWG), despite a request by EDF Renewables that the topic be directed to the Interconnection Process Task Force (IPTF). The company wants such projects to receive some reimbursement through MISO, EDF said.
Jeff Webb, MISO director of planning, said the IPTF would be appropriate if project costs were only to be shared among interconnection customers, but he doubted that cost-sharing would be that limited. He suggested that the RECBWG first discuss the potential scope for cost allocation.
A stakeholder discussion on metrics used for the SPP-MISO transmission cost allocation settlement will initially be assigned to the Resource Adequacy Subcommittee for an examination of possible capacity benefits.
Jesse Moser, MISO director of seams relations and strategy, said internal decisions on the metrics belong in the RECBWG, which is already considering broader cost allocation changes. Still, some stakeholders contended that the issue should first move into the RASC for exploration of potential capacity benefits from the settlement.
The settlement requires MISO to “conduct a stakeholder discussion regarding the use of capacity benefits as an alternative way to allocate costs” of the joint operating agreement (ER14-1736). (See “Cost Allocation Set in MISO-SPP Settlement,” MISO Market Subcommittee Briefs.)
Madison Gas and Electric’s Megan Wisersky said she was surprised to learn MISO would delve into a cost allocation discussion before assessing the resource adequacy impacts of the settlement.
Indiana Utility Regulatory Commission staffer Dave Johnston said the topic should be discussed in the RASC.
“To me, RECBWG is for transmission projects,” Johnston said. “This is not what this is. This is a settlement between parties with a bucket of money.”
