LaFleur Offers Views on SPP-Mountain West Integration

By Tom Kleckner

FERC Commissioner Cheryl LaFleur took time from a whirlwind listening tour of the Rocky Mountain region last week to visit the Colorado Public Utilities Commission and discuss the Mountain West Transmission Group’s desire to join SPP.

FERC SPP Colorado Public Utilities Commission Cheryl LaFleur Mountain West — FERC’s Cheryl LaFleur | © *RTO Insider*

Appearing Jan. 25 before the PUC’s fourth information session devoted to Mountain West’s pursuit of RTO membership, LaFleur recalled sitting in on what she said felt like the “100th meeting” of Mountain West stakeholders as they discussed the subject. SPP’s and Mountain West’s utilities are now deep into negotiations over membership, accelerating a process that began last January when the group announced its intention to join the RTO. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)

“You don’t go out on 200 dates if you’re going to break up,” LaFleur said. “There’ve been 100 since then, so it’s starting to seem pretty real.”

FERC’s most senior commissioner addressed questions from Colorado regulators, industry representatives and consumer advocates about jurisdictional issues, consumer representation in SPP and the new opportunities presented to Mountain West by recent structural developments in the Western Interconnection.

“These are exactly the kind of questions you should be asking,” she said. “There’s no time like now to ask questions of SPP, [of] the utilities that are coming to you for the authority to do this — of whomever is involved in this, because you have a critical role to play in making sure that what happens is right for the people in Colorado.”

The PUC has jurisdictional authority over Xcel Energy’s Public Service Company of Colorado and Black Hills Energy, both Mountain West members.

No Rubber Stamp

Colorado Commissioner Frances Koncilja, who has been organizing the information sessions, said she will invite CAISO, Peak Reliability and PJM to a fifth forum, in either February or March, to explain “what they think they can do for Colorado citizens.”

“This is not a decision this commissioner is going to rubber stamp,” Koncilja said. “I want to know what all the alternatives are.”

While SPP is intent on becoming Mountain West’s reliability coordinator (RC), Peak Reliability, the group’s current RC, has recently proposed to offer market services in the Western Interconnection through a joint effort with PJM. Further complicating matters, CAISO has also given 18-months’ notice that it intends to leave Peak and offer its own reliability services for half the RC’s price. (See Peak, PJM Detail Western Market Proposal and CAISO to Depart Peak Reliability, Become RC.)

LaFleur said the prospect of multiple RCs in the West will require a concerted effort by regulators and others involved to maintain the “situational awareness” developed by years of having only one.

“It will take work with multiple RCs, but I suspect if we do the work right, it can be done in the same way as we have multiple RCs in the East,” she said. “It will take some careful work to make sure the situational awareness between RCs is sustained and that everyone’s treated fairly.”

Consumer advocate Larry Miloshevich, with Energy Freedom Colorado, asked LaFleur how nonutility stakeholders could make their interests heard in the face of decisions that he said were being made behind closed doors “for reasons that are not all that clear.” Come to FERC, she replied.

“I hate to sound like a civics book, but the citizens are not unprotected. [FERC’s commissioners] are sworn to protect them. That’s our whole job. We’re not here for the utilities,” LaFleur said.

“There are probably political reasons why [Mountain West] kind of sought to be its own thing rather than being with other parts of the West, but that’s not for me to judge,” she said. “Yes, file those arguments. We’ll listen to them.”

LaFleur referred to FERC doctrine, saying the move to join an RTO “is a voluntary decision by the members who go in.” She said the commission learned this the hard way after considering a nationwide standard market design in the early 2000s.

“There was a revolution, almost coast to coast, with people saying, ‘We’ll decide who we want to sign up with, not FERC,’” LaFleur said. “FERC said, ‘If this market thing is going to take off, we’re going to let people come together and make their own decisions.’”

The commissioner extolled the benefits of RTO membership, pointing out that organized markets now cover two-thirds of the country and include regions with and without electric competition.

FERC SPP Colorado Public Utilities Commission Cheryl LaFleur — | *SPP*

“It’s worked across all different models. Why? Because you’re deploying resources over a bigger footprint, so you can run your systems more efficiently with less reserves to bring your energy to customers and hopefully keep your lights on at lower costs,” LaFleur said. “All this change, all this wind, all this solar … it’s made people stand up and say, ‘Wow, there might be something in this for our customers too.’”

It just had to grow organically in the West.

“If this came from Washington, it would be DOA. We’ve seen that through multiple attempts,” LaFleur said. “The best thing FERC could do is say nice things when invited to go somewhere but not do anything. It appears the time is approaching when we might have to do something.”

January 29, 2018

ERCOT Technical Advisory Committee Briefs: Jan. 25, 2018

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week asked its Wholesale Market Subcommittee (WMS) to determine what went wrong during two recent market events.

On Jan. 22, ERCOT disabled the 69-kV contingencies being solved by the day-ahead market (DAM) software, with the exception of a contingency included in a real-time binding constraint during the previous 30 days. Staff issued a market notice at the time.

ERCOT TAC wholesale market subcommittee — ERCOT’s Technical Advisory Committee gathers for its January meeting | © *RTO Insider*

ERCOT’s Carrie Bivens said staff followed protocols by issuing the notice. “The alternative was aborting the DAM run,” she said.

On Jan. 23, real-time prices jumped to $5,800/MWh for 15 minutes, forcing ERCOT to deploy non-spinning reserves. Prices also exceeded the energy offer cap of $9,000/MWh during two five-minute intervals.

The ISO said it was the first time market prices reached the $9,000 price cap during two security constrained economic dispatch (SCED) intervals, pointing to ramping issues because of cold weather and higher-than-expected load around 7 a.m. Resource adequacy was not a problem, ERCOT said.

Staff’s David Maggio said ERCOT doesn’t intend to reprice the event, noting the systems were “working as expected.”

“We don’t see any issue with how things worked out,” he said.

Staff said the two events were unrelated, prompting Citigroup’s Eric Goff to respond, “They felt related to everyone.”

“The issue that caused the DAM software problem was unrelated to ramp constraining in real time,” Bivens said. “They just happened on the same operating day.”

The contingencies were restored Jan. 24 for the following operating day.

“We need a discussion at WMS, because you’re determining winners and losers when you turn off contingencies,” Morgan Stanley’s Clayton Greer said during the TAC’s Jan. 25 meeting.

The WMS next meets Jan. 31. The subcommittee will also provide real-time co-optimization training following its meeting.

ERCOT Sees 62% Drop in RUC Practices

ERCOT staff’s annual reliability unit commitment (RUC) report to the TAC last week revealed a more than 62% drop in the practice.

Maggio said that 562 instructed RUC resource-hours last year resulted in 534 effective RUC resource-hours, compared to 1,514 and 1,417, respectively, for all of 2016.

Of those resource-hours, 163 were successfully bought back, a clawback percentage similar to previous years. The total RUC make-whole amount was about $540,000, which was covered through capacity short charges.

The 534 effective RUC resource-hours were all a result of congestion (433), capacity (66) and Hurricane Harvey (35). No resource-hours were committed for ancillary service shortages, system inertia or extreme cold weather/start-up failures.

Maggio pointed to several recent improvements as causing the drop in RUCs, including reducing shadow price caps for transmission constraints from about $1 million/MWh to about $100,000/MWh and a nodal protocol revision request (NPRR744) that used a common trigger to fix the opt-out decision inconsistency between the SCED and settlements systems.

Staff and stakeholders are still working to improve both RUC functionality and transparency, Maggio said.

In other staff reports:

Assistant General Counsel Vickie Leady told stakeholders that staff have developed a definition of “affiliate” in line with the typical corporate use of the word. The proposed bylaw amendment clarifies when an affiliate relationship arises between two or more ERCOT members.
Members will be allocated almost $26,000 in resettlements from the Greens Bayou Unit 5 reliability-must-run contract, after certain costs were not fully settled before applicable true-up dates. The RMR, ERCOT’s first since 2011, was approved in June 2016 and terminated effective May 29, 2017.
Controller Sean Taylor said the ISO forecasts the system administration fee will be adequate and he “sees no need for a change” through 2019. Stakeholders had requested advance notice of any fee increases during the 2016-17 budget process.

Task Force Looks at Subcommittees’ Restructuring

Stakeholders agreed to form a task force to combine or restructure the TAC’s Retail Market (RMS) and Commercial Operations (COPS) subcommittees. The task force will begin its work Feb. 5, with the intention of reporting back to the committee for its Feb. 22 meeting.

Leadership from the two subcommittees met over the holidays and agreed on three options for restructuring them. The initiative is a result of the TAC’s annual structural review of its subcommittees and input from the Board of Directors’ Human Resources and Governance Committee.

Reliant Energy Retail Services’ Rebecca Reed Zerwas will lead the task force, after she was “‘volun-told’ to get this started.”

The RMS and COPS will continue in their current forms until a solution is endorsed by the TAC.

TAC Elects Helton Chair, Coleman Vice Chair

The committee unanimously elected Dynegy’s Bob Helton as its chairman, a position he has essentially held since September. Previously vice chair, Helton stepped into the role vacated by Adrianne Brandt, who left San Antonio’s CPS Energy to join Chair DeAnn Walker’s staff at the Public Utility Commission of Texas.

TAC Vice-Chair Diana Coleman, Chair Bob Helton | © *RTO Insider*

Diana Coleman, ‎senior market specialist with the ‎Office of Public Utility Counsel, was elected vice chair.

NPRR Clarifies ERCOT’s Jurisdictional Status Quo

The TAC unanimously endorsed NPRR861, which clarifies ERCOT can and will take all actions necessary to preserve its jurisdictional status quo and market participants with respect to FERC. Possible actions include, but are not limited to, ordering the disconnection of transmission facilities and denial or curtailment of an electronic tag.

The PUC in December instructed the ISO to draw up the NPRR over concerns that transmission projects along the U.S. border with Mexico may threaten ERCOT’s electrical separation from the rest of the country and the PUC’s exclusive jurisdiction over the Texas grid operator. (See “Fending off FERC,” Texas PUC Challenging SPP-Mountain West Intertie Costs.)

FERC’s jurisdiction is derived from the Federal Power Act, which gives the commission broad authority to regulate interstate commerce by public utilities. FERC does not have plenary jurisdiction over the ISO because the energy generated in the region is not transmitted in interstate commerce, except for certain interconnections ordered by the commission that do not give rise to broader jurisdiction.

The committee also unanimously endorsed six other NPRRs, a system change request (SCR) and a nodal operating guide revision request (NOGRR):

NPRR819: Removes language referencing “data errors” for resettlement of the DAM and real-time market (RTM); gives the ERCOT board authority to direct a DAM resettlement parallel to its authority to direct an RTM resettlement; removes references to undefined “declarations” of resettlements; changes the thresholds that determine a resettlement; and fixes a semantics error.
NPRR841: Determines in real time the day-ahead make-whole payment by incorporating the ancillary services infeasibility charge, approved with NPRR782, into the payment’s analysis.
NPRR842: Defines a “study area” as an ERCOT-designated “geographic region,” separate from a weather zone or load zone, used primarily for study purposes.
NPRR844: Corrects the current process of including capacity that is modeled but not yet commercially operational in the outage scheduler, which is then reflected in the outage report.
NPRR852: Creates a more efficient approval process when updating the congestion revenue right activity calendar; removes unnecessary “advisory approval” language; and moves the calendar’s approval from the TAC to the WMS.
NPRR855: Clarifies the criteria for including new and retiring resources in the seasonal peak average capacity estimation calculations used for ERCOT’s Capacity, Demand and Reserves report. The revisions apply to wind, solar, DC ties, hydro and all-inclusive generation resources within private-use networks.
NOGRR169: Aligns the guide’s language with NERC Reliability Standard PRC-002-2 (Define Regional Disturbance Monitoring and Reporting Requirements) to determine required locations for NERC-required disturbance monitoring equipment. This relieves the burden on facility owners to adhere to two vastly different requirements for the same purpose.
SCR794: Updates how the SCED limit is calculated by the Transmission Constraint Manager to consider how the megavolt-ampere flows compare to actual limits.

— Tom Kleckner

January 29, 2018

Montana PSC Racks up 2nd Lawsuit over PURPA Rates

By Amanda Durish Cook

Montana regulators last week found themselves at the center of yet another court case regarding the rates offered to the small solar producers — this one stemming from a 2016 decision to suspend those rates at the request of the state’s largest utility.

Cypress Creek Renewables filed suit in the U.S. District Court for Montana alleging that the Public Service Commission’s action violated the Public Utility Regulatory Policies Act by denying solar developers the right to earn the PURPA rates in effect when they originally committed to sell their power to NorthWestern Energy.

PSC PURPA — Cypress Creek construction site | *Cypress Creek Renewables*

Under PURPA, utilities like NorthWestern are obligated to purchase electricity from qualifying facilities at avoided-cost rates that reflect a utility’s own cost to build new generation. The federal law leaves it to each state to determine both the rate and when a legally enforceable obligation (LEO) begins, barring any conflict with FERC regulations.

In November, the Montana PSC voted to reduce the standard PURPA contract length from 25 to 15 years and cut the energy rate available to renewable energy projects up to 3 MW from $66/MWh to $31/MWh.

But that move came after the PSC voted to allow NorthWestern to suspend its PURPA rates in June 2016 after the utility complained that the rates exceeded its avoided costs for new generation. The PSC grandfathered in facilities that had completed their agreements with NorthWestern prior to the June 16, 2016, date of the order but added the stipulation that QFs must have obtained interconnection agreements before that date to earn the previous rates.

In its lawsuit, Cypress Creek says that 13 of its solar projects that had not obtained interconnection agreements by that date are still entitled to receive the old purchase rate and contract length.

“PURPA further requires that state energy regulators like defendants recognize that, where a QF unequivocally commits to sell its output to a utility, it establishes a ‘legally enforceable obligation’ on the part of the QF to sell, and on the part of the utility to purchase, the QF’s output at the utility’s avoided-cost rate, calculated at the time the obligation is incurred,” the company wrote.

Cypress Creek also argues that at a June 9, 2016, Montana PSC hearing, NorthWestern acknowledged it was obligated under federal law to enter into long-term contracts for the 13 projects under Montana’s previous PURPA rate.

The company’s argument relies on a 2016 FERC declaratory order that found the Montana PSC violated PURPA by requiring QFs to have power purchase agreements and interconnection agreements with utilities to create a LEO, finding that the arrangement give utilities too much control over when the obligation occurs. (See FERC Declares Montana QF Requirements Illegal.)

The Montana PSC maintains that its LEO standard is still state law and has called FERC’s order nonbinding unless it is upheld by a district federal court.

“The petitioners are essentially trying to enforce FERC’s declaratory order in which the [commission] took issue with the piece of the Montana PSC’s legally enforceable obligation test, which required a qualifying facility to obtain a signed interconnection agreement,” said Montana PSC Communications Director Chris Puyear. “Importantly, FERC said nothing of the commission’s decision to suspend the rate and contract terms available to qualifying facilities up to 3 MW in size.”

Puyear pointed out that the rate available to QFs is voluntary and can be suspended at any time.

Still, the PSC disagrees that Cypress Creek had a LEO to the old contract terms on the 13 projects, as the complaint argues.

“The commission’s standard is less rigorous than many other states, some of which require a qualifying facility to be near the end of construction before a LEO can be established,” Puyear said. “While the commission remains open to revisiting its LEO test in the future, absolutely no evidence has been presented which shows that the current LEO test disadvantages qualifying facilities.”

Cypress Creek sees it differently.

“Before this rate change, the [plaintiffs] had fully committed to sell their output to NorthWestern, creating their legally enforceable obligation to sell — and NorthWestern’s statutory obligation to purchase. … NorthWestern repeatedly conceded that it had reached a final (if unsigned) contractual agreement with the QFs prior to June 16, 2016,” the company said.

Cypress Creek said it received “continued” assurances from NorthWestern in May and June 2016 that the old rates and contract lengths would apply to the 13 projects.

The company — along with Vote Solar and the Montana Environmental Information Center — is also a co-complainant in a state case alleging that the PSC last year “drastically and unreasonably” reduced the state’s PURPA standard contract length and energy rate, dealing a fatal blow to future small solar development in Montana. (See Montana PURPA Solar Saga Continues in State Court.)

In January, Cypress Creek reported its strongest-ever construction growth rate, having built 1 GW of solar installations over the previous 18 months.

January 29, 2018

CAISO Launches Interconnection Initiative

By Jason Fordney

CAISO this month launched a sweeping set of updates to its interconnection policies, an annual process made increasingly complex by a rapidly changing resource mix.

The effort “will likely address some substantial concepts but also a myriad of minor concepts that have not been addressed in some time,” the ISO said of its 2018 Interconnection Process Enhancements (IPE) initiative.

CAISO TPD — CAISO launched its Interconnection Process Enhancements 2018 initiative this month | © *RTO Insider*

“Once we finalize the scope of the initiative, we will be able to determine the issues that will be included in this year’s process and the timing for development,” CAISO said.

The program is divided into six broad categories: deliverability; energy storage; generator interconnection agreements; interconnection cost responsibility and financial security; interconnection requests; and modifications.

A Jan. 17 issue paper defined the proposals that CAISO is considering. The document includes 42 potential topics and will be developed into a draft final proposal, but the ISO has not specified when it would be presented to the Board of Governors for approval.

The deliverability category alone contains nearly a dozen topic areas related to transmission planning, criteria for commercial viability and transparency into the availability of deliverability.

Other major tasks laid out in the IPE paper include:

Ensuring the development of the most viable projects;
Giving projects with power purchase agreements a greater opportunity for deliverability; and
Providing resource developers reasonable timelines for interconnection.

The ISO expects a March ruling from FERC on last year’s more narrowly tailored IPE package, which was expedited to obtain a ruling before the next transmission plan deliverability (TPD) allocation takes place in March.

A TPD allocation provides resources the transmission capacity required to deliver power during peak conditions and is a condition of receiving full capacity deliverability status, which is critical for eligibility to be counted as resource adequacy.

CAISO twice a year allocates TPD to generating projects that meet certain criteria. The 2017 IPE package proposes a third TPD allocation, which FERC is likely to approve.

The TPD allocation process works well during periods of high procurement, CAISO said. However, renewable procurements have recently slowed significantly, resulting in few projects meeting the criteria to qualify for a TPD allocation.

There are also uncertainties around renewable procurement that will affect the ability of a resource to obtain power purchase agreements. CAISO noted that the California Public Utilities Commission has proposed establishing a two-year resource procurement cycle to meet the targets of integrated resource plans, with the first procurement proposed for the end of 2018. But modeling used by the commission for the program shows a minimal need for renewable procurement until 2026 because California utilities are on track to meet — or exceed — renewable portfolio standard targets, the ISO said.

“The IRP will have significant impacts on interconnection customer’s ability to obtain PPAs for their projects,” CAISO said.

In a Jan. 24 presentation, CAISO discussed items that stakeholders requested be included in the IPE, including a proposal that would allow interconnection customers to replace their entire project with storage during the interconnection process. But CAISO has only approved up to 10% conversion to battery from an existing project during the process.

“A complete change of technology from existing technology requires a study to determine the new electrical characteristics and the impact to the grid,” CAISO said in explaining that it would not explore that topic in IPE 2018.

The energy storage category of IPE 2018 is focused on distributed energy resources, wholly replacing existing facilities and deliverability assessment for energy storage.

The ISO is taking comment on the IPE package through Feb. 7 and said stakeholders should suggest other items that might be included.

January 29, 2018

MISO Informational Forum Briefs: Jan. 23, 2018

CARMEL, Ind. — MISO is asking stakeholders to put pen to paper by spring to describe how the RTO should measure grid resilience.

Stakeholders will participate in a broad discussion of what constitutes resilience during MISO Board of Directors Week in late March. And the RTO has asked each stakeholder sector to prepare its own whitepaper on the topic.

During a Jan. 23 Informational Forum, MISO CEO John Bear celebrated FERC’s recent decision to reject Energy Secretary Rick Perry’s proposed rulemaking to financially support nuclear and coal-fired generators, instead requiring RTOs to answer questions about how they assess resilience. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.) Bear said MISO is committed to promoting reliability and resilience throughout its footprint, emphasizing that no near-term reliability issues exist, attributable in part to the RTO’s partnership with state regulators.

DOE’s original rulemaking timeline didn’t allow for “reasoned decision-making and thoughtful review,” Bear added.

“A one-size fits-all wasn’t feasible in MISO given our diverse footprint,” he said, promising to work with stakeholders in drafting a response to the order. MISO Director of Planning Jeff Webb last week said the RTO is still holding internal meetings to formulate its response.

MISO Website Officially Migrates

MISO’s officially launched its redesigned website on Jan. 16, and market reports and real-time data feeds are up and running, said Kacey George, the RTO’s digital strategy adviser.

“We had 12 million hits on the first day,” George said.

MISO expects to upload planning and training materials as well as leadership and governance pages by the end of the month, she said. Staff must also address a few bugs, namely involving some member pages related to the interconnection queue.

The old website will be preserved at old.misoenergy.org into spring as a contingency, should something go wrong with the new site. (See Winter Launch for MISO Website, Market System Project.)

December Ops

Lower natural gas prices and relatively light congestion translated into lower year-over-year prices for MISO in December despite slightly higher load.

Shawn McFarlane, MISO executive director of strategy, said average temperatures in the RTO’s footprint last month ranged from 1 to 6 degrees Fahrenheit colder than the 30-year average, driving the increase in load. But prices averaged $27.26/MWh, 11% lower than the same period a year earlier.

“We were about $3/MWh lower than what we saw last year,” McFarlane said.

He credited the lower prices to a 25-cents/MMBtu drop in gas prices and lower congestion compared with the previous December. Average load was up 0.8 GW to 77.7 GW, and load peaked at 98.8 GW on Dec. 27, a 5.8% increase over the average monthly high.

“Multiple rounds of arctic air swept through the footprint” during the month, McFarlane said, making load forecasting challenging and leading to two days with a poor unit commitment score in MISO’s monthly self-assessment.

“Holiday loads … are always kind of tricky to figure out,” he said.

McFarlane also said MISO had to manage high market-to-market congestion with SPP in December because of high wind output and transmission outages in SPP.

MISO Shuffles Leadership

MISO has made several leadership changes in the new year, Bear said.

Todd Ramey will now exclusively head MISO’s market platform replacement effort, leaving his role of vice president of system operations to become vice president of system enhancements, a new position. MISO is poised to spend $130 million by 2024 to replace its aging market platform with a more adaptable modular system.

Former Executive Vice President of Operations and Corporate Services Richard Doying will step away from the operational side of MISO to focus exclusively on designing a market for the future.

“Everything is on the table here,” Bear said of Doying’s new role. “Put some simulations in place and stress it. What concerns me is not so much the next five years, but the five years after that … and the queue shows that. If we don’t get ahead of the curve, we’ll be chasing it.”

Bear said the markets were designed in 2005 and not equipped for today’s realities of more exact forecasting, high wind penetration and copious amounts of data.

“Quite frankly, it’s hard to keep the system safe. It wasn’t designed for the environment we live in today,” Bear said.

MISO Board of Directors Resilience MISO Informational Forum Entergy — Todd Hillman (left) and Charles Rice | © *RTO Insider*

Finally, MISO South Vice President Todd Hillman will transition to become head of external affairs.

Additionally, in December, MISO revealed a plan of executive succession that promoted Clair Moeller from vice president to president of MISO, and will have Moeller stepping into the role of CEO should something unforeseen happen to Bear. (See MISO Board Promotes Moeller, OKs 2018 Budget.)

Entergy New Orleans CEO Talks Big Easy Challenges

MISO welcomed Entergy New Orleans CEO Charles Rice during the meeting for a brief conversation of the challenges and considerations of powering the Big Easy.

“It’s a pretty unique place in terms of the population density and the geography. We’re surrounded by water on three sides. For us to import power into the City of New Orleans is very challenging and very difficult,” Rice said.

The city has little right-of-way space for additional transmission lines, Rice added.

The CEO highlighted the need for the planned, $210 million, 128-MW natural gas-fired plant within city limits at the site of Entergy’s retired Michoud plant. He has previously warned that the city has only 1 MW of generation within its borders and needs a more reliable, onsite generation source. The proposed plant currently awaits New Orleans City Council approval; city advisers rejected an earlier proposal from the utility for a larger, more expensive plant.

Hillman asked how Entergy New Orleans plans to prepare for the increased likelihood of another hurricane.

“We never stop preparing. We prepare year-round for hurricanes,” Rice said. “And after … we take a look at what went right, what went wrong.”

Entergy is still in the process of replacing natural gas pipelines damaged by Hurricane Katrina in 2005. “Right now, we’re probably focused on the largest gas infrastructure project in the country,” Rice said.

Rice said New Orleans’ demographics make providing utility service a delicate balance: “37% of my customers live at or below the poverty level, so I’m always thinking of that,” Rice said. “When we make decisions, we have to make sure it’s something our customers can afford.”

He said New Orleans is making strides in its goal of having up to 100 MW of rooftop solar located within the city and will pursue other new technologies, such as building microgrids at hospitals in the coming years.

“There’s going to come a time when customers are going to want to have 100% control of their energy,” Rice said. “If customers want a microgrid, we have to give them a microgrid. If they want rooftop solar, we’re going to have to figure out how to make that work.”

MISO traditionally holds its springtime quarterly board meeting within the city’s French Quarter; this year’s meetings occur March 27-29.

— Amanda Durish Cook

January 28, 2018

CAISO Floats Reliability Programs Revamp

By Jason Fordney

CAISO last week kicked off an effort to implement major changes in the way it procures backstop generation needed to maintain grid reliability, in the face of growing stakeholder dissatisfaction over increased use of the practice.

The ISO is reviewing its reliability-must-run (RMR) and capacity procurement mechanism (CPM) programs and considering combining the two. It considers both backstop procurements to be “last resorts” to guarantee adequate capacity when it identifies generation deficiencies, as well as to prepare for unexpected events on the grid.

CAISO is undertaking the effort “to address concerns identified by the ISO and by other stakeholders” in light of recent RMR and CPM designations, it said in a Jan. 23 straw proposal and issue paper.

“This initiative will review the RMR tariff provisions, pro forma agreement and procurement process, and seek to clarify and align the use of RMR procurement and backstop procurement under the CPM tariff,” CAISO said.

CAISO has recently increased its reliance on RMRs and CPMs for gas-fired power plants, which are unpopular with owners of other resources competing in the market, as well as state regulators who favor non-fossil-based resources. The ISO in recent months has inked contracts with gas plants, citing misalignments with state resource adequacy programs as one reason for doing so.

CAISO backstop procurements RMR — CAISO has signed RMR contracts with four natural gas-fired power plants | *CAISO*

The initiative will also look at reworking the ISO’s Condition 1 and Condition 2 classifications for RMR units, which have different payment structures. The former recover only a portion of their revenue requirement, while the latter operate under a full cost-of-service payment methodology.

Following recommendations from the ISO’s Internal Market Monitor, the proposal seeks to remove certain limits on market participation currently imposed on Condition 2 resources and make both types of units subject to must-offer obligations for energy and ancillary services. In a protest of the Metcalf RMR filed at FERC, the Monitor said consumers are currently bearing full costs for Condition 2 facilities that are barred from CAISO markets in many hours.

The grid operator’s Board of Governors in November approved the latest RMRs, with Governor Ashutosh Bhagwat saying: “I am going to hold my nose very, very hard” while voting in favor. (See Board Decisions Highlight CAISO Market Problems.)

But the California Public Utilities Commission responded on Jan. 11 by fast-tracking a nullification of the RMRs. (See CPUC Retires Diablo Canyon, Replaces Calpine RMRs.) Representatives from the CPUC and Pacific Gas and Electric told the ISO board in public meetings that they opposed the contracts.

CAISO RMR backstop procurements — The California Public Utilities Commission on January 11 nullified CAISO’s RMRs with Calpine | © *RTO Insider*

Grid planners are being pushed into backstop procurements to maintain longer-term reliability as gas generators fail to obtain contracts under California’s resource adequacy program. CAISO has 852 MW of capacity under RMR, including Dynegy’s Oakland units and Calpine’s Feather River, Yuba City and Metcalf Energy Center plants, all of which were signed in September-November 2017.

The involuntary RMRs receive a negotiated rate, and CPMs receive a market-based price subject to a cap. The cost of the contracts eventually falls on retail ratepayers, which must shoulder tens of millions of dollars, often with relatively short notice.

Some power marketers say the rapid growth of community choice aggregators has further scrambled the procurement picture as customers depart from investor-owned utilities, leaving a small rate base to shoulder the costs.

CAISO said it wants to develop the first phase of the new program enhancements in time for May approval by the board. A second phase would be in place this fall to be used in 2019 and would clarify when RMR is used instead of CPM and explore whether the two designations can be merged.

The ISO has already posted a detailed presentation for a Jan. 30 stakeholder meeting to be led by Keith Johnson, manager of infrastructure and regulatory policy.

January 28, 2018

FERC Accepts Disputed GIA for Rhode Island Generator

By Michael Kuser

FERC on Friday accepted an unexecuted large generator interconnection agreement (LGIA) filed by ISO-NE and National Grid for Clear River Energy’s 1,100-MW natural gas-fired plant in Burrillville, R.I. (EL18-349).

The commission’s Jan. 26 order rejected Clear River’s protests over the dates for providing financial security for the cost of required transmission upgrades; its request to self-build certain interconnection facilities; its cost responsibility for transmission upgrades; and its request for additional data backing the cost allocation.

Clear River’s twin one-by-one combined cycle generating units will interconnect with the grid at National Grid’s existing Sherman Road 345-kV switching station through a new 345-kV generator lead line. During LGIA negotiations, Clear River requested to push back the initial commercial operation date two years, to May 31, 2021. National Grid confirmed that it could meet the new deadlines.

Clear River complained that the unexecuted agreement would require it to begin spending up to $88 million prior to the project’s permits being secured.

The commission ruled that the milestones developed by National Grid were based on the schedule proposed by Clear River. “Clear River’s request to adjust the dates by which it must issue its notices to proceed and post security appears to be due to permitting delays. We note that, if Clear River prefers to proceed once it receives the required permits, then it is free to propose later key milestone dates. National Grid has stated that it will re-evaluate the other milestones should Clear River avail itself of this option.”

The commission also rejected Clear River’s request to self-build its interconnection facilities, saying that option is only available if National Grid is unable to meet Clear River’s milestone dates.

FERC also found that ISO-NE had provided all the information it is required to in justifying Clear River’s $44 million in transmission upgrades.

FERC ISO-NE National Grid GIA Clean River Energy — | *Clear River Energy*

It also rejected Clear River’s request to restudy its cost obligation because of the two-year delay in its proposed commercial operational date. The company said some upgrades in its LGIA will not be necessary because of several transmission projects expected to be online by 2021 in the Southeast Massachusetts/Rhode Island area: the New Grand Army switching station; upgrades to the Somerset Substation; and upgrades to transmission lines X3 and W4.

FERC said Clear River’s decision to delay its commercial operating date was not grounds for triggering a restudy under ISO-NE’s Tariff.

In November, Clear River had filed a separate complaint asking FERC to eliminate provisions in the RTO’s pro forma LGIA that permit the direct assignment to interconnection customers of network upgrade-related operations and maintenance costs (EL18-31). On Jan. 23, however, the company filed to withdraw the complaint.

“Clear River believes it has shown that, given the nature of the relevant upgrades (which consist almost entirely of replacing or relocating existing network facilities), there very likely would be no monetary impact on Rhode Island ratepayers whatsoever. Nevertheless, the relief sought by Clear River has proven contentious in the Rhode Island Energy Facility Siting Board (EFSB) proceeding regarding Clear River’s application for the permits necessary for the project to be constructed,” the company said. “Accordingly, in order to remove this issue from being considered in any way in the EFSB proceeding — and to eliminate even the false perception of negative ratepayer impact — Clear River is submitting this notice of withdrawal.”

FERC’s Jan. 26 order noted that the notice of withdrawal remains pending. “The commission’s determination in this case should not be read as prejudging the resolution of any substantive issue in that proceeding,” it said.

January 28, 2018

FERC OKs ISO-NE FCA 12 Filing; Rejects Protests

By Michael Kuser

FERC accepted ISO-NE’s informational filing for Forward Capacity Auction 12, rejecting protests from a demand response provider and renewable generators over qualification rules (ER18-264).

The commission’s Jan. 19 order agreed with the RTO’s list of resources that qualified for the Feb. 5 auction for the 2021/22 delivery year. It also approved the three capacity zones to be modeled, which are unchanged from FCA 11.

ISO-NE FCA 12 forward capacity auction ferc — | *ISO-NE*

Efficiency Maine Trust — a quasi-state agency that administers energy efficiency programs in Maine and is overseen by the state Public Utilities Commission — protested the RTO’s methodology for calculating existing capacity qualification values. The agency said ISO-NE inappropriately subtracts the amount of expiring measures from a demand resource’s qualified capacity from a prior FCA, rather than from the demand resource’s actual and known performance capacity, as reported in ISO-NE’s energy efficiency measure database.

ISO-NE rules define qualified capacity — the quantity for which a capacity supplier is compensated — as the lower of the resource’s summer or winter qualified capacity. When a capacity supplier’s summer and winter qualified capacity is significantly different, as is the case with the Efficiency Maine programs, the supplier will not receive compensation for the higher seasonal capacity unless it can pair the higher capacity with other resources in a composite offer.

Efficiency Maine said the RTO’s rules would deny it compensation for $3.7 million in capacity for FCA 12, although it said it has been able to reduce the loss to $1.5 million through composite offers covering its entire qualified summer capacity.

The commission said Efficiency Maine projects performed above their qualified capacity because measures installed after the initial clearing of the resources. “We agree with ISO-NE that Efficiency Maine should have sought to qualify any additional capacity prior to such additional measures being in service. Accordingly, to the extent that the Efficiency Maine projects’ overperformance is the result of Efficiency Maine’s failure to seek to clear new incremental capacity in the FCA, we find it inappropriate to now mitigate the consequences of that action (or inaction) through changes to the demand resource methodology.”

The commission also agreed with the RTO “that it would be inappropriate for the commission to require ISO-NE to use Efficiency Maine’s proposed methodology for the Efficiency Maine projects while still using the current demand response methodology for all other energy efficiency resources with expiring measures.”

Renewable Technology Resource Exemption

The commission also rejected a joint protest by CPower and Tesla, which combined to enter Tesla’s SolarCity rooftop generation into the auction.

The companies asked the commission to require ISO-NE to re-evaluate the renewable technology resource (RTR) designation for five solar projects and one combined solar and fuel cell project.

The projects passed the RTO’s qualification process and were assigned the default offer review trigger price (ORTP) — a price floor based on the cost of new entry — of $12.864/kW-month. CPower said it did not challenge the ORTP because it sought to use the RTR exemption to receive an offer floor price of $0/kW-month. RTO rules permit up to 200 MW of RTR exemptions annually to renewable resources receiving out-of-market revenue through state renewable portfolio programs.

In October, however, ISO-NE rejected CPower’s application as incomplete. CPower contended the additional information the RTO requested meant that new resources must already be accepted into a state RPS program and receiving revenue to qualify for RTR designation, contrary to the RTO’s Tariff.

ISO-NE responded that although CPower’s qualification package was sufficient to determine an appropriate capacity amount to qualify each resource, it lacked details necessary to determine whether each resource met the requirements for an RTR designation.

The commission sided with the RTO.

“Although CPower’s qualification package contains some location-specific information and that CPower’s RTR submittal contains general information on possibly applicable RPS statues and regulations, we agree with ISO-NE that neither sufficiently enable ISO-NE to determine the specific provisions and manner (e.g., on an individual or aggregate basis) in which the renewable projects seek RPS qualification,” the commission said. “We agree that such specificity is necessary for ISO-NE to have sufficient certainty that the renewable projects will still qualify as RTR resources by the time of the relevant capacity commitment period. Thus, we find that CPower failed to comply with the Tariff’s requirements to obtain RTR designation.”

Zones and Resources

As in FCA 11, ISO-NE will model three capacity zones in FCA 12: Southeastern New England (Southeastern Massachusetts, Rhode Island and Northeastern Massachusetts/Boston), which will be modeled as import constrained; Northern New England (Maine, New Hampshire and Vermont), which will be modeled as export constrained; and Rest of Pool (Connecticut and Western/Central Massachusetts).

The installed capacity requirement (ICR) is 34,683 MW. After accounting for 958 MW per month of Hydro-Québec interconnection capability credits, FCA 12 will procure a net ICR of 33,725 MW.

ISO-NE qualified 5,605 MW of new resources and 35,007 MW of existing resources: 30,702 MW from intermittent and non-intermittent generation; 82 MW from imports; and 3,224 MW from demand resources.

The RTO said 2,309 MW of static de-list bids — one-year exemptions from the auction — were submitted for FCA 12.

January 28, 2018

PSO Rate Case a Concern for AEP’s Akins

‘Terrific Year’ for NextEra

American Electric Power beat Wall Street’s expectations with a positive yearend earnings report last week, but CEO Nick Akins spent much of a conference call with analysts focused on its Public Service Company of Oklahoma (PSO) subsidiary and its rate case before state regulators.

Akins referred to “disappointing” outcomes in its previous and current rate cases, which have left PSO with a regulated operating return on equity of 6.2% — the second-lowest among AEP’s operating companies and below an authorized ROE of 9.5%. He said AEP may invest its money elsewhere without improved returns, noting the company pulled “several hundred million dollars” of investment out of Oklahoma after PSO’s previous rate case.

PSO AEP earnings Nick Akins — PSO’s Tulsa Power Station | *Flickr*

“We have plenty of places to put our capital, and so Oklahoma would wind up being sort of in the red area,” Akins said during the Jan. 25 call. “That’s something we take very seriously because we want to make investment in Oklahoma.”

An administrative law judge has recommended a 5% ROE in PSO’s current rate case before the Oklahoma Corporation Commission, a “negative trend” Akins is hopeful will be reversed. If the OCC approves the ALJ’s recommendation, “That’s just another really bad message about investment in Oklahoma.”

Moody’s Investors Service recently downgraded PSO’s rating outlook from stable to negative, saying its “limited cushion … for deterioration in financial performance” would be “incrementally impacted” by the recent changes in federal tax law. “We now expect key credit metrics to be lower for longer,” Moody’s said.

“Now that PSO is on negative credit outlook by Moody’s, a positive result is even more important,” Akins said. “[PSO] doesn’t deserve the ROE recommendation and it doesn’t deserve the outcomes that we’re getting in Oklahoma. We’re going to let the commission speak on this. I really believe that the commission will be responsive, so let’s just wait and see what that order looks like.”

Also key to AEP’s future success in the Sooner State is its $4.5 billion Wind Catcher project, a 2-GW wind farm in the Panhandle that will deliver energy to PSO and its sister company, Southwestern Electric Power Co. AEP is seeking regulatory approvals in Oklahoma, Arkansas, Louisiana and Texas, while PSO is gathering community input on proposed transmission siting.

“We are in a very critical time in the life of this project,” Akins said. “In my mind, it would be an absolute travesty to let this unique hedge against the market pass, and I remain confident that it will get done.”

The Columbus, Ohio-based company reported fourth-quarter operating earnings of 85 cents/share, beating Zacks Consensus Estimate of 81 cents/share. AEP recorded a profit of $1.9 billion in 2017, triple the $611 million the year before, although sales were $15.4 billion, down from $16.4 billion.

Year-end earnings were $3.68/share, down from $3.94 from the year-ago period. AEP’s share price finished the week at $68.77, down almost 12% from its 52-week high of $78.07.

NextEra Reports $5.38B Profit in ‘Terrific Year’

NextEra Energy on Jan. 26 reported a 2017 profit of $5.38 billion, though that number was adjusted down to $3.17 billion after allowing for the effects of tax legislation and other unusual charges. Still, that was up from $2.88 billion in 2016.

The Florida-based company said its revenue increased to $17.2 billion, up from $16.2 billion in 2016.

“It was a terrific year,” said CEO Jim Robo.

However, the company’s adjusted fourth-quarter earnings came in at $1.25/share, falling short of the Zacks’ estimate of $1.31/share. The company reported fourth-quarter GAAP net income of $2.16 billion.

NextEra said its Florida Power & Light utility will reduce customer bills by using federal tax savings to forgo recovery of $1.3 billion in Hurricane Irma restoration costs. It said NextEra Energy Resources added a record 2.7 GW to its contracted renewables backlog.

NextEra stock gained $2.83 on Friday to close at $157.69/share, up 1.8% on the day. Its share price has gained almost 30% over the last 12 months.

— Tom Kleckner

January 28, 2018

FERC Denies CPower DR Audit Waiver

By Michael Kuser

FERC last week denied CPower’s request for a one-time waiver to replace the results of a failed demand response audit with those of a more successful one conducted a week later (ER18-185).

ISO-NE FERC demand response audit CPower — | *ISO-NE*

In its request, the energy management company said that it had asked ISO-NE on July 17, 2017, to perform an audit of its real-time demand response resources (RTDRs). But when the RTO initiated the audit July 19, a communications problem prevented CPower from receiving the audit dispatch signal, causing most of the company’s resources to fail to perform. CPower pointed out that ISO-NE is the only RTO in the country that does not back up DR dispatch signals with an email, text message or phone call.

As a result of the failed audit, CPower concluded the month with a demand reduction value of nearly zero.

ISO-NE’s Tariff requires seasonal testing of RTDRs to establish their capabilities and ensure they are available to respond during an emergency event.

The RTO suggested that CPower request a second audit to “mitigate partially” the negative impacts of the first. A July 26 audit demonstrated 94% of the claimed capacity that CPower had registered in the RTDR program, and the company asked the grid operator to replace the July 19 results with those of July 26.

ISO-NE denied the request, saying its Tariff stipulates that a second audit cannot replace an initial audit conducted during that same month. It further argued that allowing RTDRs “another bite at the apple” to replace a poor performance during an audit could compromise the significance of such audits or impact future performance.

The RTO also said that granting the waiver would harm third parties by requiring the resettlement of capacity payments away from resources that followed dispatch instructions and performed well during their audits.

FERC agreed with ISO-NE, saying that CPower’s request was “not of limited scope because it would require rerunning market settlements” and thereby affect other market participants. The commission also noted that allowing resettlement would result in preferential treatment for CPower compared with other RTDRs that also performed poorly in the audits.

“Further, granting waiver would have broad implications on the effectiveness of auditing rules. It could undermine the integrity of audits — which by their nature test performance during unpredictable conditions — and impact future performance of RTDR,” the commission said.