Page 1451 – RTO Insider

April 11, 2016

NYPSC: Minimal Cost to Meet 50% Renewable Goal

By William Opalka

New York consumers will see little change in their electric bills as the state switches to renewable energy resources at an accelerated pace, according to a study released by the Public Service Commission on Friday.

The Clean Energy Standard cost study puts a price tag on the state’s goal of generating 50% of its electricity from renewable resources by 2030.

“New York can meet its clean energy targets with less than a 1% impact on electricity bills (or less than $1 per month for the typical residential customer) in the near term and shows net positive benefit of $1.8 billion by 2023,” the study says. “… The current combination of low energy prices, low interest rates and available tax credits presents a uniquely favorable environment for near-term investment into renewables.”

The net benefit includes EPA’s “social cost of carbon” — an estimate of climate change damages, including changes in agricultural productivity, human health, property damages from increased flood risk and changes in energy system costs. It is projected at about $24/MWh in 2023.

The CES is part of New York’s Reforming the Energy Vision initiative to switch the state’s energy generation mix to cleaner and more distributed resources. It also promotes the preservation of upstate nuclear generation during a transitional period until 2030.

The cost study builds on a white paper released in January that outlined the policy goals (15-E-0302). (See New York Would Require Nuclear Power Mandate, Subsidy.)

PPAs vs. RECs

The study’s base case assumes power purchase agreements and renewable energy credits would be used equally to procure the 5.2 GW of Tier 1 renewables envisioned by 2023, which would be dominated by land-based wind (38%) and solar power developed under the NY-Sun initiative (52%). By minimizing investors’ exposure to commodity price risk, procuring capacity through PPAs would be far cheaper than procurement through RECs, the study said.

Changes in CES program costs as a result of energy prices would be balanced by the effect on ratepayers’ overall bills. “For example, lower-than-expected energy prices could increase the CES program costs, but this would be offset by a reduction in energy bills from lower wholesale energy prices,” the study says.

Nuclear Incentives

The New York CES is unique in that it promotes financial incentives to keep upstate nuclear power plants viable through 2030 to retain their carbon-free generation as the state transitions to renewable resources. (See related story, Environmental Group Urges Ill. Legislators to Save Nuclear Plants.)

“In addition to the cost and benefits quantified in this study, there are significant economic development benefits identified — for example, the proposal to provide new support for upstate nuclear plants would protect 25,000 direct and indirect jobs, $3 billion in direct and indirect economic activity and $145 million in state tax revenue,” according to the study.

Nuclear plants would be subsidized with a formula based on their costs of service. The study used a range of program costs — from $59 million to $658 million — based on low and high assumptions of the cost of generation of nuclear power and future energy prices.

Zero emission credits for nuclear plants will be based on an “open book” assessment of plants’ costs. Detailed cost estimates were not published in the study “to avoid prejudicing this process,” the study said.

The Upstate Energy Jobs Coalition of business, labor, economic development and other organizations reacted swiftly to the news.

“The state’s analysis confirms what most of us already know, which is that the costs of allowing upstate nuclear plants, with all of their economic and clean energy benefits, to close prematurely greatly outweigh the costs of implementing the CES,” said L. Michael Treadwell, CEO of the County of Oswego Industrial Development Agency. “The closure of FitzPatrick, Ginna and Nine Mile Point would be a severe blow to the economy upstate, a region that’s already struggling to turn its economy around.”

Entergy has said its James A. FitzPatrick plant would close despite state efforts to keep it operating. (See NYPSC OKs Ginna Deal.)

April 11, 2016

PJM Operating Committee Briefs

PJM is proposing to continue winter testing but stop compensating Capacity Performance players for it.

Operating Committee Chairman Mike Bryson said the idea is that those participants would be expected to factor the cost into their offers.

After some members questioned that plan, Bryson said he would take their comments back to PJM for further discussion.

The cold weather testing for 2015/16 yielded little in the way of useful data because the winter was so much warmer than the previous season, PJM’s David Schweizer told the committee. (See “Cold Weather Testing Cheaper, Longer than Previous Year,” PJM Operating Committee Briefs.)

“We don’t have much of a story to share here. It was an oddball winter,” he said. “It’s hard to draw any conclusions.”

Phasor Data Quality Task Force Sunsetted, Issue Moved to SIS

Members voted to sunset the Phasor Data Quality Task Force and transition the issue to a quarterly special session of the Systems Information Subcommittee.

“We’d like to continue to discuss the issue, but it’s not necessary to have a whole task force,” PJM’s Suzie Fahr said.

The special session will tack on about two hours quarterly to an SIS meeting, she said.

The task force was created under the SIS in December 2013 to improve the quality of synchrophasor data so that it could reliably be integrated into operational decision-making.

Since the group’s inception, the error rate of synchrophasor production data has shrunk from 14.35% to 2.45%.

PJM to Study Frequency Response for FERC Inquiry

PJM is conducting an internal analysis in response to FERC’s Feb. 18 notice of inquiry regarding frequency response, Eric Hsia told the committee. (See FERC Seeking Comments on Primary Frequency Response.)

The commission is seeking comment on whether new or existing resources should be required to have frequency response capabilities. It also wants to know the nature of frequency response compensation within the market optimization process.

PJM will present the results of its review at the May OC meeting.

Hsia said most resources that don’t provide frequency response are 10 MW or less and lack governors. Often these are distributed resources.

Operating Review Shows Perfect Dispatch Saved $33M YTD

A review of operating metrics showed that perfect dispatch has saved $33 million so far this year, with cumulative savings of $1.2 billion since the program was implemented in 2008.

Perfect dispatch, designed to measure how well PJM commits combustion turbines, is the hypothetical least production cost commitment and dispatch — what PJM would spend if it knew and could control all system conditions in advance.

The perfect dispatch rate this year through March was 83.92%.

The average load forecast error performance for March was 1.71%, within the goal of 3%. For the first quarter, all zones had errors below 3%, excluding East Kentucky Power Cooperative, which was above 4.5% (see chart).

The average forced outage rate through March was 3.48%, or 6,252 MW, with the total rate at 13.15%, or 24,743 MW.

– Suzanne Herel

April 11, 2016

PacifiCorp Offers Lessons for Future EIM Participants

By Robert Mullin

PORTLAND — PacifiCorp says future participants in the western Energy Imbalance Market (EIM) should benefit from early lessons the company learned in its efforts to integrate its real-time operations with CAISO.

The EIM got off to a rocky start in November 2014 as transmission constraints between California’s and PacifiCorp’s balancing areas produced price discrepancies that consistently required out-of-market mitigation measures. That issue was resolved by NV Energy’s entry into the market last December, which significantly improved transfer capacity among the regions.

During the first public meeting of the EIM Regional Issues Forum at Bonneville Power Administration offices Wednesday, PacifiCorp staff discussed the challenges and benefits of joining the EIM.

“The first thing I would say is PacifiCorp had the honor of doing this first,” said Sarah Edmonds, PacifiCorp Transmission vice president and general counsel. “Luckily, a lot of those bumps in the road have been addressed.”

A New Language

Edmonds said prospective EIM participants will first need to grasp a new lexicon. “The EIM and the ISO have a whole new set of acronyms that you have to know,” she said.

The second piece of advice: Look at your maps.

“The West is very special,” Edmonds said. “It has all kinds of special arrangements that are grandfathered in. Go talk to your neighboring balancing areas.”

Stuart Kelly, PacifiCorp vice president of major project delivery, said one of the biggest challenges concerned what data to exchange with CAISO, especially data that relate to market settlements.

“Not just the output [to CAISO], but the input back into your system,” he said. Kelly encouraged participants to meet with CAISO staff early in the integration process to learn how the ISO settles transactions.

“I think most operations are not set up to handle the rapidity [of the EIM] and the settlement process,” Edmonds added, noting that dispute rights over energy transactions have time limits. For that reason, an EIM participant must streamline its procedure for generating “shadow settlements” — the participant’s own payout estimates from a transaction — which can differ from those ultimately provided by the ISO.

The settlement process affects not only an EIM members such as PacifiCorp but also non-affiliated utilities within an EIM balancing area that must rely on PacifiCorp to facilitate their EIM transactions. Clay MacArthur, assistant vice president of power marketing and contracts for Deseret Power, said settlement delays have caused problems for his Utah-based electric co-op.

“When you go into nine months and longer [for some settlement data], some of the market signals you thought you would get, you don’t get on a timely basis,” MacArthur said. He added that settlement statements from PacifiCorp at times provide either too much or too little data, requiring the utility to “reverse engineer” the documents to determine what they mean.

“We recognize there are improvements to be made in our settlements,” Edmonds said.

Better Visibility, More Discipline

Joining the EIM also presents new challenges for physical operations.

Describing his company as “a little bit of a problem child” because it operates two balancing areas, PacifiCorp’s Kelly stressed that EIM participants must ensure their network models can be exported to CAISO to facilitate integrated operation.

CAISO EIM Forum, Pacificorp — CAISO control room *Source: CAISO*

“If you’ve got [variable energy resources] in your portfolio, you have to get a handle on your forecast,” he said. “The challenge will be predicting when you have some kind of ramp.” Kelly said CAISO’s forecasting model was better than what PacifiCorp had previously relied upon.

Kelly also described outage management under the EIM as “a whole new language” that his company had to get right in order to coordinate schedules with the ISO. He pointed out CAISO’s requirement that it be notified of any system upgrades three months in advance.

“What the EIM requires is a level of discipline in those areas that you have never experienced,” Edmonds said.

That discipline appears to be spilling into neighboring Northwest balancing areas, whose system operators must coordinate with EIM participants.

“I think the implementation issues are getting simpler,” said Russ Mantifel of BPA’s transmission and policy group. “Right now I think we’ve now proved a concept to use EIM to move megawatts that can be scaled up. I think there’s increased visibility and control.”

Edmonds called visibility into neighboring balancing areas “one of the iterative, evolving parts of the EIM.”

Bidirectional Learning

Lessons from the EIM have not been a one-way street, according to forum participants.

“On the other side of the equation, the ISO is learning its own form of Western multiculturalism,” Edmonds said, noting that CAISO must deal with the capabilities of other areas while maintaining its own balancing area. “There’s a bilateral need to understand each other and each other’s lexicons.”

“A lot of these matters are very complex,” said energy consultant Tony Braun, an EIM Transitional Committee member. “You can’t know how complex until you’re in them.”

Despite the complexity, Kelly said PacifiCorp recovered its integration costs within the first year of operation because of the increased efficiency of the market.

“After seeing the benefits, I would encourage others to join,” he said. He also pointed to what he called NV Energy’s “seamless” integration into the market late last year. (See NV Energy has Smooth EIM Integration, CAISO Says.)

“We could not have gotten there as easily as we did — and it was not easy — if not for PacifiCorp having problem-solved a year before,” NV Energy attorney Lauren Rosenblatt said.

April 11, 2016

Artificial Island Cost Increase Could Lead to Rebid

By Suzanne Herel

VALLEY FORGE, Pa. — PJM planners are rethinking a piece of the Artificial Island project, a move that could alter its scope and possibly require the RTO to solicit new bids under FERC Order 1000.

Salem-Nuclear-Generating-Station-on-Artificial-Island-(Wikimedia)-for-slider, ferc order 1000 — Salem Nuclear Generating Station on Artificial Island

The move comes after Public Service Electric and Gas submitted estimates that nearly doubled the cost of its section of the stability fix from $137 million to $272 million. (See Cost Estimate of PSE&G Portion of Artificial Island Fix Doubles to $272M.)

“We are looking at options to mitigate the cost,” Steve Herling, PJM vice president of planning, told the Transmission Expansion Advisory Committee on Thursday.

PJM has been working with PSE&G and consultants to analyze the cost estimates and design, and their work is nearly done, said Paul McGlynn, PJM general manager of system planning.

The project involves building a 230-kV transmission line from the New Jersey complex housing the Hope Creek and Salem nuclear reactors under the Delaware River to Delaware. Calls for proposals went out three years ago.

After a long, contentious process, LS Power won the job of building the line, largely because of its promise to cap construction costs at $146 million.

LS Power: ‘Nothing Has Changed’

“From LS Power’s standpoint, we’re committed to working with PJM and looking at these alternatives,” Vice President Sharon Segner told the committee. “Our cost cap remains the same. Nothing has changed.”

PSE&G was assigned the tasks of expanding the Salem substation and building a static VAR compensator (SVC) at New Freedom. PSE&G’s work is considered an upgrade and does not include a cost commitment.

Pepco Holdings Inc. was tapped to oversee interconnecting the new substation to the existing Red Lion-Cartanza and Red Lion-Cedar Creek 230-kV lines in Delaware. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)

Herling said planners now are considering a new configuration that would terminate the transmission facility at Hope Creek instead of Salem. The buildings abut each other, and Hope Creek would give contractors more room to work, Herling said. However, unlike Salem, it is not on the water, where the horizontal directional drilling to bring in the line would end.

Overhead construction is not an option because of existing 500-kV lines, he said, so the line would have to be buried. But the drilling is not precise; it would have to be done in a wide sweep around the Salem substation, Herling said, or vaults would have to be built.

Timeline at Risk

Any significant change to the plan will affect the timeline, he said. “It could take another year, putting the system at risk,” he said.

There’s also the chance that altering the configuration would end up being just as expensive or simply move the cost from PSE&G’s end over to LS Power’s portion. Expense will have to be weighed with constructability and risk, Herling said.

“Clearly, this is a change in scope for LS Power and PSE&G,” Herling said. “We’re still looking at process implications.”

In an interview, Herling said if that change in scope is challenged, FERC could rule that the project needs to be rebid.

PJM will be reviewing the project with the Board of Managers, which meets next week, but will not be making a recommendation.

“The board may give us more things to go look at,” he said. “We will be working this as quickly as we possibly can to have the board make a decision.”

The project has been controversial not only among the companies that vied for the contracts, but as well as with regulators and consumer advocates in Delaware and Maryland, where most of the cost would be assigned.

In response to complaints, FERC suspended the project’s cost allocation pending additional review, which included a technical conference in January (EL15-95). (See Commenters: DFAX Cost Allocation Inappropriate.)

April 11, 2016

Eversource CEO Retiring; CFO Named Replacement

By William Opalka

Eversource Energy CEO Tom May will retire in a month and be replaced by current CFO Jim Judge, the company announced Wednesday.

May, 68, will become board chairman after the company’s annual shareholders meeting May 4 in Boston. Under the succession plan, Judge will join the board next month and become chairman at Eversource’s annual meeting in 2017.

James J Judge Eversource Energy 2016 — Judge

May and Judge have worked together for 38 years. For the past 22 years, before and during a series of mergers, May has been CEO of Boston Edison, NSTAR and Northeast Utilities, which was renamed Eversource Energy in 2015. (See Northeast Utilities Rebranding as Eversource Energy.)

NSTAR and Northeast Utilities merged in 2012 to create an electric and gas utility company in Connecticut, Massachusetts and New Hampshire with 3.6 million customers and a market capitalization of $18 billion. The company has joint headquarters in Boston and Hartford.

“Tom May has been an extraordinary leader for more than two decades as chief executive. He has delivered superior results in every category — customer, financial, operations, safety and community,” Sanford Cloud, lead trustee of the board, said in a statement.

Judge will remain in his role as Eversource CFO until a successor is named.

Besides pursuing growth and acquisitions, May has become known for forging partnerships with developers to propose controversial projects that would bring fuel resources into New England.

In 2008, NSTAR and Northeast Utilities formed a joint venture, Northern Pass Transmission, to import Canadian hydropower supplied by Hydro-Quebec through New Hampshire. That project, vehemently opposed by some environmentalists and natural gas generators, is currently undergoing site evaluation by state officials. (See Committee Rules Northern Pass Application Complete.)

Eversource also has a 40% stake in the proposed $3 billion Access Northeast natural gas pipeline with partners Spectra Energy and National Grid. The pipeline would run through New York, Connecticut, Rhode Island and Massachusetts. (See Algonquin Submits Pre-Filing Request for Access Northeast Pipeline.)

Pipeline plans have generated controversy as some state regulators have endorsed a regional plan to have funding come from electricity customers. (See Massachusetts Regulators Endorse Pipeline Contracts.)

April 11, 2016

Dominion: Tx Project Should be Regionally Allocated

By Suzanne Herel

Dominion Resources is asking FERC to rehear two related February decisions in which the commission reversed a previous order and ruled that transmission projects that solely address a transmission owner’s local planning criteria are not eligible for regional cost allocation (ER15-1387).

In its first application of the rule, FERC said Dominion was solely responsible for the cost of its $160 million, 500-kV Cunningham-Elmont rebuild (ER15-1344). (See FERC Does 180 on Local Tx Cost Allocation in PJM.)

Dominion also has filed a protest of PJM’s compliance filing, which FERC required in its February determination.

The company requested that FERC rule on the rehearing request at the same time it decides on PJM’s compliance filing.

Also asking for rehearing are Old Dominion Electric Cooperative, LSP Transmission Holdings and ITC Mid-Atlantic Development.

Meanwhile, PJM requested a clarification on how it should apply the new methodology to certain projects in its Regional Transmission Expansion Plan.

In its rehearing request, Dominion argued that its proposal has regional benefits and is unlike 98% of Form 715 projects whose costs are designated to the local TO because they deliver only local benefits.

“The other 2% have had their costs allocated at least 50% regionally because they belong to a cost allocation class previously determined to have regional benefits,” it said. “Nothing about the 98% statistic explains why such projects no longer have regional benefits.”

April 11, 2016

Wabash Valley Acquires Struggling Peabody Energy’s Share in Prairie State

By Amanda Durish Cook

FERC last week approved Wabash Valley Power Association’s acquisition of a 5% interest in two 800-MW coal-fired units at the Prairie State Energy Campus for $57 million — less than a quarter of what seller Peabody Energy paid (EC16-62).

Wabash Valley - Peabody Energy - Prairie State Energy Campus — Prairie State Energy Campus *Source: Peabody Energy*

Wabash Valley, an Indianapolis-based generation and transmission cooperative, said the transaction will add 83 MW to its 1,105 MW of generation capacity, most of which is in MISO.

Peabody Energy, which had paid $246 million for its share in Prairie State, agreed to sell to Wabash Valley following a competitive bidding process, part of a restructuring that has resulted in the sales of almost $500 million in assets since last year. Nevertheless, Peabody, the world’s largest private-sector coal company, said last month it may have to file for bankruptcy protection because of its inability to meet debt payments.

The city of Martinsville, Va., a customer of American Municipal Power, which has a 23% interest in Prairie State, filed a comment expressing concern that the sale would diminish the value of the southwestern Illinois facility and result in increased rates for its customers. The city said the sale price values the facility at about 80% less than the indebtedness for which the communities are liable under their power sales agreements.

The commission declined Martinsville’s request to conduct an inquiry into whether the sale would create a hardship for the communities paying debt service, saying it was outside the scope of its merger review authority. In addition, the commission said that the commenters “fail to explain [how the sale] might result in increased rates for wholesale customers.”

April 11, 2016

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — PJM moved the day-ahead energy market offer deadline to 10:30 a.m. from noon without incident April 1, PJM’s Adam Keech told the Market Implementation Committee Wednesday.

“We didn’t have many people complaining, ‘We missed the window,’” he said.

Offers were cleared in 2.5 hours on average, within the desired three-hour window. It helped that the system load was light, he said.

Commented Independent Market Monitor Joe Bowring: “We did notice that the liquidity of the gas market had not shifted to earlier in the morning just yet.”

But when he asked members if anyone else had observed the same, no one spoke up.

The scheduling change aims to better align the gas and electric markets. (See PJM Moving on Day-Ahead Schedule Changes.)

Members Endorse New Way to Measure Emergency DR

Members unanimously endorsed changes in how demand response is measured and verified in emergency situations.

Existing procedures, which use the hour before an event as the default customer baseline (CBL), can be inaccurate in the early morning or on days with multiple dispatches, PJM’s Pete Langbein said. It also can require a cumbersome administrative review process.

The new method changes the emergency energy default CBL from the hour before to the current default economic CBL.

It also eliminates the ability to create an economic registration after the fact and use the CBL to settle the event.

The new process is expected to measure energy load reduction more accurately and be consistent with the calculation of non-summer compliance under the new Capacity Performance model.

The changes were ready to be implemented in 2014, but PJM held off until the Supreme Court ruled that DR would remain in the energy market. (See Supreme Court Upholds FERC Jurisdiction over DR.)

Allocating Spot-in Service for NYISO Imports to be Studied

With seven abstentions, the committee approved a problem statement and issue charge to study how to improve the process of allocating spot-in transmission for energy imports from NYISO.

Vitol’s Joe Wadsworth, who presented the proposal, said the timing of the markets and the first-come-first-serve method of reserving spot-in transmission make it difficult for participants to efficiently schedule such imports.

PJM opens the window to reserving next-day spot-in service at 9 a.m., but NYISO doesn’t release its day-ahead market results until at least 9:35 a.m. and sometimes as late as 11 a.m., Wadsworth said.

Thus, participants who use spot-in transmission to compete on near-term import supply opportunities at the seam may have to reserve the service before they find out what has cleared in NYISO, he said.

Spot-in is free but limited in quantity, and there is no priority for participants who have cleared the NYISO market.

“If you can’t get spot-in transmission for your imports, then your day-ahead transactions can be curtailed, and suddenly you may have exposure to real-time prices,” he said.

Work on the issue is expected to take six to nine months.

No one voiced similar concerns with MISO at the meeting.

Changes to Emergency Procedures Tool Coming in May

Members received an update on PJM’s emergency procedures, which are changing because of the June 1 implementation of Capacity Performance.

Initial adjustments will be visible in the online emergency procedures tool on May 5 so they may be used for the summer emergency procedures drill, which is scheduled for May 10.

More changes will come on May 26. They include new fields, tabs, timestamps and flags giving members information on performance assessment hours.

Also new is a “deploy all resources” action for emergency events that occur without warning as opposed to evolving over time. The purpose of the action is to instruct members to dispatch all generation resources and implement load reductions immediately.

24-hour Max Run Time Parameter Set for June 1

PJM intends to implement a maximum run time parameter value of 24 hours June 1 for all generation resources except for pumped hydro power and market sellers who believe their resource cannot meet that value.

Documentation to that effect must be submitted to unitspecificpls@pjm.com by April 20.

Supporting documents must include original equipment manufacturer specifications of unit constraints.

Max run time values will be issued by May 15.

Settlement C Discussion Terminated

Members voted to approve the Market Settlement Subcommittee’s request to stop work on establishing a “Settlement C” method that would allow electricity distribution companies to resolve billing errors beyond the 60-day Settlement B time frame.

The group had been working on the issue since September.

In a subcommittee poll of 22 responders representing 119 participants, 40% voted to continue to develop a solution, while the rest chose maintaining the status quo. At the MIC, 64% voted to kill the initiative.

PJM Proposes Clarifications to Bilateral Transactions

PJM proposed revised rules regarding bilateral capacity transactions that would maintain the physical nature of the deals to ensure members’ indemnification.

In such transactions, a seller transfers capacity to a buyer but retains the obligation for performance. (See “PJM Proposes Clarifications to Capacity Bilateral Transactions,” PJM Market Implementation Committee Briefs.)

The proposal assigns bonus payments to the buyer in proportion to the megawatts transacted. It also requires that any replacement transactions entered into by the seller be traceable. Therefore, this would not be able to be done in an incremental auction.

“If they went into an incremental auction to do this, all the parties would lose the visibility of who now is [providing the capacity that was] originally part of the bilateral,” Assistant General Counsel Jen Tribulski said. “We thought that these transactions would be best served if the seller was able to replace them, but not by an incremental auction.”

The clarifications will require a Tariff change.

— Suzanne Herel

April 11, 2016

Idaho Power Inks Agreement to Join Western EIM

By Robert Mullin

Idaho Power on Wednesday signed an agreement with CAISO to become the sixth utility to join the western Energy Imbalance Market (EIM).

The Boise-based company, which serves about 525,000 customers in southern Idaho and a portion of eastern Oregon, expects an April 2018 start date, pending approval from federal and state regulators.

Inclusion of Idaho Power would bring an additional 4,800 miles of transmission into the EIM while improving the market’s access to an area of Wyoming that renewable developers — including EIM member PacifiCorp — seek to tap for wind projects intended to serve the West Coast.

“The market already has proven itself to increase network efficiency, lower costs and encourage cleaner energy into the power grid,” CAISO CEO Steve Berberich said in a statement. “With each new entrant, the market will only multiply those benefits.”

CAISO launched the EIM in November 2014 in partnership with the Portland-based PacifiCorp, which operates more than 16,000 miles of transmission spanning 10 states. Unlike in an RTO, the EIM’s transmission-owning entities retain operational control over their assets, while member generators participate in the real-time market on a voluntary basis.

Nevada-based NV Energy joined the EIM in December 2015, broadening the market’s footprint and filling a transmission gap between load centers in California and generating resources located in the PacifiCorp East (PACE) balancing area. (See NV Energy has Smooth EIM Integration, CAISO Says.)

“With the entry of NV Energy, [CAISO] transfer capacity with PACE has gone from around 200 MW to 571 MW,” Eric Hildebrandt, CAISO director of market monitoring, said during an April 6 Regional Issues Forum held in Portland. “This has really been a game changer.”

Idaho Power’s membership could provide a similar — if more limited — enhancement to the market. The utility’s service territory sits adjacent to both the NV Energy and PACE balancing areas, providing increased transfer capability with the remote northeastern corner of PACE, the wind-rich area of western Wyoming.

Although wind developers see the region as a promising source of wind exports, transmission constraints — and California’s restrictions on renewable imports not delivered directly into an in-state balancing area — have impeded development of large-scale projects to serve California. Idaho’s entry into the EIM, along with possible ISO membership for PacifiCorp, could open the door for development as CAISO’s boundary effectively extends eastward, expanding RPS eligibility for a larger pool of resources.

In a deal that seemed to anticipate yesterday’s announcement, Idaho Power and PacifiCorp last year swapped $43 million in Idaho and Wyoming transmission assets, reallocating ownership of lines and equipment designed to move power westward from the massive Jim Bridger coal-fired generating plant. One result of the deal: PacifiCorp gained access to an additional 200 MW of “dynamic service” out of western Wyoming, short-term transfer capability that facilitates integration of variable renewable resources. For its part, Idaho Power expected the new arrangement to boost its transmission revenues, reducing the company’s revenue requirement from ratepayers.

Two other Northwest utilities will precede Idaho Power into the EIM. Washington-based Puget Sound Energy is scheduled to join this October, followed by Portland General Electric in October 2017.

April 11, 2016

MISO Market Subcommittee Briefs

MISO will not build an application programming interface (API) to provide five-minute schedule data to customers.

“MISO is not recommending to pursue this function at this time,” MISO’s Matt Schingle said during an April 5 Market Subcommittee meeting.

At the December MSC, Kansas City Power and Light requested creation of an API to retrieve market participants’ physical schedules from webTrans or the e-tag system.

Schingle said too few stakeholders wanted the change for it to be cost-effective. “This year, there’s not enough flex in the budget for this kind of cost,” he said. MISO’s vendor estimated the API would cost $150,000 to develop.

Schingle said the raw data is already available through customers’ internal market software, although MISO does not provide a function allowing customers to retrieve schedule profiles.

MISO Moves Ahead on PJM Coordinated Transaction Scheduling; Monitor Slams PJM Fees

MISO could begin publishing monthly price forecasts for MISO-PJM Coordinated Transaction Scheduling (CTS) as early as May 13, according to Beibei Li of MISO’s market evaluation and design team.

Designed to reduce uneconomic power flows, CTS will allow traders to submit bids that would clear only when the price difference between MISO and PJM exceeds a threshold set by the bidder.

Li said MISO expects to publish the final CTS price forecast report template by April 22 and is seeking MSC feedback by April 19.

Dave Johnston of the Indiana Utility Regulatory Commission asked if CTS transactions would be subject to uplift. Li said MISO did not believe that uplift charges would apply.

CTS came under criticism in a recent Independent Market Monitor quarterly report, with Monitor David Patton contending the program is currently “accomplishing very little” because of poor forecasting and fees imposed by PJM. Patton said PJM’s charges at the seams were similar to MISO’s revenue sufficiency guarantee payments.

While Patton said the Monitor supports MISO’s FERC filing to add CTS to its Tariff (ER16-533), his group filed comments asking the commission to require that PJM eliminate all uplift charges. MISO has already proposed excluding charges such as the revenue sufficiency guarantee and revenue neutrality uplift.

Patton said CTS is “much more liquid and effective” without uplift charges, as illustrated by trading across NYISO’s seams with ISO-NE and PJM.

“We’re hoping that FERC reads our filing and orders PJM to eliminate all charges,” he said.

The Monitor is also working with MISO and PJM to develop proposals for firm capacity delivery as an alternative to pseudo-tying resources to PJM, Patton said.

“I continue to be amazed that PJM thinks this pseudo-tie requirement is necessary,” he said. “They’re not thinking of what’s best for the Eastern Interconnect.”

MISO will pseudo-tie about 2,000 MW of new generation into PJM for the 2016/17 planning year and more than 2,500 MW during the next two planning cycles. Only 155 MW of new generation was pseudo-tied in the 2015/16 planning year.

Need for 30-Minute Reserve Product Questioned

MISO is revisiting the merits of developing a 30-minute reserve product despite stakeholder questions about the need for the requirement.

The RTO is reviving the idea because natural gas generators are being used increasingly as baseload resources, rather than just meeting peak demand.

MISO has assigned the project “medium” priority on its Market Roadmap, with evaluation expected to be complete by the end of the third quarter, according to Leonard Ashley of MISO’s market evaluation and design team. He said the project would emerge as a major market implementation if developed.

The 30-minute reserve product would be designed to respond to a large loss of generation within a constrained area, said Jeff Bladen, executive director of market design. He said the product was a “necessary evolution of market design” and could address systemwide reliability instead of local reliability.

Bill SeDoris, director of MISO integration for Northern Indiana Public Service Co., asked if the issue could be solved simply with use of an increased reserve requirement.

“That’s one way to do it,” MISO’s Kevin Larson responded. “I don’t think that’s the most economic way to do it.”

Bladen said the RTO’s initial assessment shows that creating a 30-minute reserve is less costly than carrying additional spinning reserves or regulation reserves.

Thomas Sikes of WPPI Energy asked if MISO could replicate its 2013 report that concluded a short-term reserve product was unnecessary.

Ashley said MISO is just beginning to evaluate the project, and conceptual design wouldn’t start until late this year.

“We didn’t mean to give the impression that the ship has been built and set sail. … We definitely haven’t made the decision that a 30-minute product is the way to go,” Ashley said.

FTR Working Group may be Absorbed by MSC

Brad Arnold, chair of the Financial Transmission Rights Working Group, said his group is considering merging with the Market Subcommittee due to light agendas and infrequent meetings. The group last met Jan. 8.

Arnold said the working group would meet to discuss possible 2016 initiatives and figure out if there are enough to justify the group’s existence.

MISO to Hold August Market Symposium

Bladen reported that MISO would hold a first-ever market symposium Aug. 18-19. Bladen said the symposium would center on two main themes: shifting environmental regulations (Day One) and the future of distributed resources (Day Two). He said the symposium will be “taking the temperature” of the industry by bringing in experts from around the country to speak.

Registration instructions will be posted sometime this week.

The MSC also approved the Seams Management Working Group’s largely unchanged charter.

— Amanda Durish Cook