Page 1291 – RTO Insider

May 29, 2017

PJM Markets and Reliability Committee Briefs

WILMINGTON, Del. — Mike Bryson, PJM’s vice president of operations, announced at last week’s Markets and Reliability Committee meeting that a scheduled vote on new pseudo-tie provisions would be postponed because of ongoing negotiations with MISO.

Members were expecting to be asked to endorse several items related to creating a pro forma pseudo-tie agreement, including the agreement, a pseudo-tie reimbursement agreement and associated Tariff and Operating Agreement revisions. However, Bryson, who substituted as chair of the meeting for CFO Suzanne Daugherty, said discussions continue with MISO to overcome differences between the two grid operators. (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)

PJM Markets and Reliability Committee pseudo-tie — Anders (left) and Bryson | © *RTO Insider*

The proposal, developed through the Underperformance Risk Management Senior Task Force, would make deliverability requirements uniform for resources within and outside of PJM’s footprint and require feasibility studies for all pseudo-ties. Existing pseudo-ties would have five years to conform to the deliverability standards for internal resources.

Coal Replaced by Gas and Nuclear in 2020/21 BRA

PJM’s Jeff Bastian reviewed the Base Residual Auction results from May 23, noting that coal-fired generation cleared about 3,450 MW less than last year while gas and nuclear increased 3,700 MW and 1,500 MW, respectively.

Wind, solar and hydro all cleared fewer megawatts this year than last. (See related story, Capacity Prices down in Most of PJM in 1st Year of 100% CP.)

“Here we see the reduced offerings of resources that might have a hard time because of their intermittency meeting the CP,” Bastian said.

Roy Shanker, an industry consultant, asked about negative megawatts of capacity transfer rights in the MAAC locational deliverability area, which cleared roughly $9.50 higher than the rest of the RTO at $86.04. The negative CTR megawatts mean there’s less load paying for the capacity in that region than there is capacity receiving the LDA’s price, Bastian said.

“[It’s] a function of that area’s share of the peak load forecast, which is a disconnect completely from the way the load is represented at the clearing of the auction, so you can have that kind of an outcome,” he said.

Exelon’s Jason Barker asked PJM to develop a written explanation of how CTRs were calculated to describe how negative megawatts can occur.

Bastian noted that the Duke Energy Ohio/Kentucky LDA, which cleared about $54 higher than the rest of the RTO at $130, was modeled individually “due to potential for deactivations in that area,” which might reduce the amount of power potentially deliverable to the LDA below the amount PJM feels is required for reliability.

“We find it prudent to model them from a reliability perspective,” he said, noting that it’s been done before in the PPL, BGE and ComEd LDAs. Of the three, only the ComEd LDA has ever separated from the rest of the RTO, he said.

American Electric Power’s Dana Horton asked how 119 MW of solar could clear as Capacity Performance, given that the sun usually isn’t shining during the morning and evening daily demand peaks in winter, when resources are most likely to be called. This auction was the first year in which all resource offers must comply with CP rules that require year-round availability and impose stricter nonperformance penalties if units fail to be available.

“The sun does shine in the winter,” Bastian said. “There was a recognition by the resource owners that there’s more risk involved with offering solar, so that the annual quantity is significantly lower than what those resources were required to offer in the past.”

Greg Carmean, the executive director of the Organization of PJM States Inc., asked if all nuclear units cleared, but Bastian declined to address the specific unit results. Barker confirmed for attendees that not all nuclear plants cleared, apparently referencing the company’s Three Mile Island, which the company announced earlier had not cleared for the second year in a row.

New Black Start Units Will Have New Annual Revenue Requirements

Stakeholders endorsed by acclamation changes to the annual revenue requirements for black start units. PJM and its Independent Market Monitor had previously come to an agreement on the time periods for member submission of data and review by the Monitor. They also agreed on having the revenue go into a non-interest-bearing account for each unit until its costs have been approved, at which point the RTO will conduct a true-up. (See “PJM to Review Black Start Prior to New RFP,” PJM Market Implementation Committee Briefs.)

The move comes as PJM prepares for its second request for proposals on black start units, which is scheduled for 2018 for projects to be available in 2020.

PJM Defends Interest in Paying for Frequency Response

Stakeholders endorsed by acclamation a problem statement and issue charge on analyzing generator requirements for primary frequency response, but not before renewing debate over compensation.

FERC issued a Notice of Proposed Rulemaking last November that would require primary frequency response for all new units except for nuclear plants. The NOPR did not address compensation. At previous meetings, the Delaware Public Service Commission’s John Farber has challenged PJM’s plan to investigate compensation and requested language be added to the problem statement and issue charge that allowed it only “if appropriate or necessary.”

“The intent is to ensure that it’s not a given that compensation is required,” Farber said on Thursday, responding to an inquiry from Public Service Electric and Gas’ Gary Greiner about why the text was added.

PJM staff reiterated the RTO’s desire to study whether units should be paid for maintaining primary frequency response capabilities.

“Back at the [Operating Committee meeting] in the fall, PJM made a statement about how we didn’t think compensation was necessary,” Bryson said. “We’re clearly more open minded about that now, and the wording of the issue charge is intended to imply that.”

Stakeholders eventually agreed on discussing potential compensation mechanisms and recommending compensation changes “if appropriate or necessary.”

FTRs to Get a Longer Perspective

Members endorsed by acclamation a proposed problem statement and issue charge to consider changes to long-term financial transmission rights modeling.

PJM’s Regional Transmission Expansion Plan looks out up to three years into the future in ordering upgrades, but approved projects aren’t captured in FTR analyses because they are only able to capture information on a six-month horizon.

“It is concerning to PJM that today, the current process is not capturing these upgrades. Because what this means to us is that they’re not fully transparent to the market participants,” PJM’s Asanga Perera said.

In the documents, PJM guaranteed that FTR-capability allocations would be made “without violating firm transmission customer priority rights.”

Other FTR changes developed in response to the FERC order impacting the annual revenue rights and FTR process also were endorsed during the meeting, though not without some modifications.

PJM requested endorsement for Manual 6 revisions, which prompted Mike Cocco of Old Dominion Electric Cooperative to request that the phrase “no longer viable” describing transmission paths be clarified.

Monitor Joe Bowring questioned PJM’s planned changes for the FTR forfeiture process.

“I would ask that you give it more thought,” he said.

Steve Lieberman of American Municipal Power followed Bowring’s comment with a motion to defer a vote on that language until next month. (The Monitor is not a member and could not make the motion on its own behalf.)

Stakeholders worked on the proposal, and PJM’s Brian Chmielewski returned later in the meeting to seek endorsement of the revised package. Per Bowring’s request, the forfeiture changes were removed, he said, and “no longer active” was substituted for “no longer viable,” along with a definition of the phrase that matched the definition in the Tariff.

Stakeholder Approvals

Stakeholders endorsed by acclamation several manual revisions and other operational changes:

Manual 3: Transmission Operations. Revisions developed in response to a periodic review.
Manual 14D: Generator Operational Requirements. Revisions to develop requirements for solar generation facilities, in compliance with FERC Orders 828 (Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities), issued July 21, 2016, and Order 764 (Integration of Variable Energy Resources), issued June 22, 2012. (See FERC Issues Ride-Through Requirement for Small Generators.)
Manual 36: System Restoration. Revisions developed in response to a periodic review.
Manual 13: Emergency Operations. Attachment E updated with 2017/18 load forecast and Mid-Atlantic load shed allocation information; Attachment F updated with 2017/2018 load shed capabilities and allocation percentages. The data in the attachments affects only transmission owners and has been validated by them.
Governing-document revisions to allow for monthly correction of meters for pseudo-tied units and dynamic schedules. (See “Meter Correction Initiative OK’d,” PJM Market Implementation Committee Briefs.)
An updated charter for the Incremental Auction Senior Task Force, which was created in response to a problem statement by Direct Energy that was approved by the MRC in November 2016. The revisions reflect an increase in scope resulting from a problem statement by NRG Energy on replacement capacity that was approved in March 2017. The revisions set a target for completing work and making recommendations to the MRC by January 2018. (See “Stakeholders Approve Variety of Actions,” PJM Markets and Reliability and Members Committees Briefs.)

Members Committee

The Members Committee held its monthly meeting last week at PJM’s Annual Meeting. (See PJM Annual Meeting Celebrates RTO’s First 90 Years.)

— Rory D. Sweeney

May 29, 2017

MISO Steering Committee OKs IMM Proposals for Market Roadmap

By Amanda Durish Cook

MISO’s Steering Committee recommended that all but one of a handful of the Independent Market Monitor’s oft-repeated recommendations be included on the 2018 Market Roadmap as potential market rule changes.

Most of the recommendations have already been brought up in Market Subcommittee meetings or are part of past State of the Market reports.

MISO’s 2016 stakeholder redesign process dictates that for issues to be discussed in stakeholder meetings or added to the Market Roadmap list, they must first be submitted to the Steering Committee for a committee assignment. The Market Roadmap is a prioritized and tracked list of market revision goals that stakeholders and the RTO agree to pursue in stakeholder meetings.

The Steering Committee made the decision to move the following recommendations forward during a May 24 conference call:

Improving shortage pricing by revising the operating reserve demand curve to reflect a higher value of lost load. (See “Patton Seeks Increase in VoLL,” MISO, IMM Differ over Scarcity Pricing Changes.)
Establishing regional reserve requirements and cost allocation through expansion of a 30-minute reserve product. MISO stakeholder relations staff member Justin Stewart said the issue might be too similar to a project already on the Roadmap that will create short-term capacity reserves, so the Steering Committee added the Monitor’s recommendation to the existing project candidate.
Changing the day-ahead margin assurance payment and real-time offer revenue sufficiency guarantee (RSG) payment rules and performance incentives to reduce gaming. The Monitor last year suggested some wind generators were deliberately over-forecasting to collect more RSG payments; the issue is expected to surface in this year’s State of the Market report. (See IMM Report Highlights Outages, Wind Over-Forecasting.) Stewart said the issue was similar to an existing Roadmap project to tighten thresholds on uninstructed deviations from dispatch orders, which is currently in the software development phase. Steering Committee members nevertheless assigned the Monitor’s suggestion new candidate status.
Creating a method for validating wind suppliers’ forecasts and using the results to alter dispatch instructions if needed, and improving forecasting incentives by modifying deviation thresholds and settlement rules. The two wind recommendations were added to an existing Roadmap candidate covering dispatchable intermittent resource modifications.

The one recommendation not added to the Roadmap was that MISO consider the economic cost of congestion, not just reliability, before granting planned outages. We Energies’ Tony Jankowski said the issue has existed “for over 10 years.”

state of the market report MISO Steering Committee — The Monitor’s suggested operating reserve demand curve in blue. | *Potomac Economics*

“You’re venturing down a road here of what’s acceptable congestion or excessive congestion. … I don’t see this as being a simple Roadmap item,” he said.

Other stakeholders agreed to table the issue, with some predicting the topic will be raised again in the next State of the Market report. Last month, MISO stakeholders took up a separate outage issue, debating whether resources on extended outages should be barred from participating in future Planning Resource Auctions. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)

The deadline for submitting candidates for consideration in the 2017 Market Roadmap project selection was May 11. Market improvements submitted after the deadline will be considered for prioritization in the 2018 Market Roadmap process.

May 29, 2017

CPP’s Fate Leaves States, Markets to Drive Grid Decarbonization

By Robert Mullin

ANCHORAGE, Alaska — State policies, market forces and technological advancements will continue the decarbonization of the electric industry regardless of the fate of EPA’s Clean Power Plan, current and former utility regulators said last week.

EPA clean power plan — Little | © *RTO Insider*

“I think the Clean Power Plan is pretty much dying,” Doug Little of the Arizona Corporation Commission said during a panel discussion on environmental policy in the “aftermath” of the CPP at the annual meeting of the Western Conference of Public Service Commissioners last week.

“It’s only a question of how it’s going to die. Right now it’s on life support. The question in my mind is, over the next several months, will the EPA pull the plug on the life support and see if it lives in any form, or will they drive a stake through its heart?”

Arizona on Path to Compliance

Little said what happens to the CPP under the Trump administration will make little difference to his state, which opposes implementation of the policy.

The final rule from EPA was “actually something that was achievable” and the state’s utilities “did a tremendous job” of incorporating the emissions targets in their integrated resource plans, Little said.

“And, they’re not, in my view, going to essentially take that whole planning process that they spent the last two years working on and just throw it away,” he said. “The direction that they’re going to continue to take is the direction that they’ve been planning to take over the last couple years.”

Tim Echols of the Georgia Public Service Commission echoed Little’s take.

“To continue with Doug’s analogy about the hospital, I really think the Clean Power Plan is going to die — [but] not from the stake. I think it’s going to die from a lack of payment on the hospital bill. And they’re going to have to unplug it because in the regulatory hospital, not everybody gets service regardless of the situation in the emergency room,” Echols said.

The “non-payment” is the Trump administration’s proposed 31% cut to the EPA budget, Echols said.

“I don’t know how they do corporal punishment in Alaska or Hawaii, but I think President Trump is taking the EPA out behind the woodshed, putting them in timeout, whatever you want to call it,” Echols said. “And you know what? That’s not unusual for a president to make those kind of decisions. Think about what President Obama did to the [Nuclear Regulatory Commission] and to Yucca Mountain when he got elected.”

Political, Practical Concerns in Georgia

Already speaking of the CPP in the past tense, Echols said that he had two problems with the plan, one political and the other practical.

The political issue: that the CPP would have turned the appointed head of Georgia’s Environmental Protection Division (EPD) into an “energy czar.”

“Now I’m not appointed by the governor, nor are my four colleagues, and this was going to put the EPD administrator essentially in charge of the energy plan for the state,” Echols said. He noted that Georgia’s rural electric cooperatives are nonprofits “that don’t take their orders from the EPD,” leaving the burden for compliance on the state’s major investor-owned utility, Georgia Power.

Echols’ practical concern: “How it picked winners and losers. The big winner, of course — natural gas.”

To comply with the rule, states would be forced to close coal-fired plants. That — along with the trend of nuclear plant closures — would leave the power sector exposed to increase gas prices in the future, Echols contended.

“Personally, I’m glad the EPA’s in timeout. I’m not saying I don’t like clean air. I’m not saying I don’t value clean water. But this agency went way too far, and the president is sending a message, and frankly I think it’s the right message.”

Two-State Perspective

Robert Kenney, vice president of state regulatory relations at Pacific Gas and Electric, California’s largest utility, said he could grasp both sides of the CPP debate.

“California has been very explicitly, vocally and unabashedly supportive of the Clean Power Plan. PG&E in particular has been vocally supportive of the Clean Power Plan. And I think that’s probably not surprising when you think about California’s position relative to taking steps to combat climate change,” said Kenney, a former Missouri regulator.

PG&E is ahead of schedule in meeting California’s 33% by 2020 renewable portfolio standard. Including hydroelectric and nuclear, the company’s portfolio is already 70% greenhouse gas free, so “the Clean Power Plan wasn’t viewed as a barrier,” Kenney said.

“Now contrast that to my experience in Missouri, where 80% of our generation was coal-fired, and the Clean Power Plan presented significant challenges,” Kenney said. “Many of the utilities that I regulated were vocally opposed to the Clean Power Plan on a variety of different legal grounds and on practical economic grounds.”

Those utilities were faced with possibly having to strand coal-fired assets in which they had invested billions to comply with EPA’s Mercury and Air Toxics Standards. That, said Kenney, was “difficult to get your brain around” as a regulator.

“I think what you will see in the aftermath of the Clean Power Plan is that states will continue to individually determine how [they] are going to deal with climate change depending on the particular state,” Kenney said.

Low gas prices in Missouri are already leading to the retirement of some of those coal-fired plants, regardless of the CPP, a development Kenney expects to continue.

Hawaii: Exempt but Vocal

Lorraine Akiba of the Hawaii Public Utilities Commission noted that although her island state is exempted from the CPP, the state’s attorney general has weighed in to support the plan against court challenges. Hawaii has enacted the most ambitious RPS in the country — 100% by 2045.

She predicted there will be “big fights” in Congress over the CPP and the EPA budget.

“This is what democracy is about. You know, last time I looked, we’re not an oligarchy and not a dictatorship. That’s the beauty of democracy. You see four different commissioners up here, with four similar but different viewpoints,” Akiba said.

Market Forces

With or without the CPP, the panelists agreed, market forces will continue the drive away from coal and toward gas and renewables.

“What really is affecting the direction towards renewables — and the direction away from some of the fossil fuels like coal — is sub-$3 gas,” said Little, who also touted the fact that his state enjoys more than 300 days of sunshine a year, making it fertile ground for the continued expansion of utility-scale solar.

Still, Little said that he’s “very concerned” about what FERC and the wholesale markets will do to “more properly value” baseload resources such as coal and nuclear to ensure grid reliability.

“I’m going to be interested to see what happens after my friend Rob Powelson and Neil Chatterjee get onto FERC and see how they’re going to address this with some of the changes in the market,” Little said. (See related story, No Fireworks for FERC Nominees at Senate Hearing.)

Kenney said technological advances are key drivers of both the market forces and environmental policy leading to decarbonization. Included among those advances: the improvement in natural gas fracking techniques and advances in PV solar cell production that has dramatically reduced costs.

“We’ve got technological advances that are giving us the tools to” execute low-carbon policies, Kenney said.

Akiba said she agreed that market forces will help determine the future. “I disagree with some of my colleagues that coal is coming back. Coal’s never coming back. Coal’s not economically viable for this country,” she said.

The fight against climate change will continue outside D.C., Akiba argued.

“States are the leaders in this. Cities are the leaders. And I shout out to Atlanta, Ga.,” Akiba said, referring to Echols’ home state. “The City Council and mayor there just adopted a 100% renewable portfolio standard for their city.”

Akiba also encouraged the conference to consider the economic benefits of reducing GHG emissions, saying “the rest of the world is going to decarbonize regardless of the rhetoric coming out of Washington, D.C.”

“There are opportunities for economic growth in renewable energy technology, new developments in electrification of transportation [and] alternative transportation. If we let that opportunity go, China is right there.”

Signs of Climate Change in Alaska

Proclaiming that he wanted to get in his “2 cents” as a former politician, panel moderator Norman Rokeberg of the Regulatory Commission of Alaska offered some sobering personal observations of climate change in his state.

“Alaska is an oil and gas state. It pays the freight up here,” Rokeberg said. “As a result, it’s been difficult to not favor the use of fossil fuels, particularly natural gas. We have 305 trillion cubic feet of natural gas stranded on our North Slope.”

He turned to his point.

“I do want to take this moment to make clear and declare that climate change and global warming is real, and you see the signs of it everywhere in this state.”

Rokeberg listed the evidence: the recorded warming of the Arctic, which is melting sea ice and increasing acidification of the ocean, affecting Alaska’s fisheries; melting permafrost undermining the foundations of the state’s roadways and infrastructure; and a changing habitat in which more plants and shrubs are growing in Arctic areas.

“I’m a gardener — a green-thumber — and I’ve lived in Alaska all my life,” Rokeberg said. “And in the last 25 years, I’ve seen the growing season extend as much as two to four weeks — that is to say from approximately four months to five months in a short period of time. That’s pretty extraordinary when you think about it.”

Rokeberg then took off his politician’s hat and replaced it with that of a regulator.

“It’s real, but make your own decisions about causation, or things like that,” he said. “We don’t need to get into that — not as regulators.”

May 29, 2017

ISO-NE to Offer Clustered Interconnection Requests in Maine

By Michael Kuser

WESTBOROUGH, Mass. — ISO-NE is working to adopt clustering methodology, already used by every other ISO/RTO in the country, to speed the development of new transmission capacity, particularly to help free wind power trapped in Maine.

Transmission bottlenecks that prevent Maine’s wind generation from reaching load centers in Massachusetts and Connecticut could be relieved by allowing large and small generators to pool their interconnection requests, Al McBride, director of system planning, told the Planning Advisory Committee on Wednesday.

McBride presented a Maine Resource Integration Study that showed how generators in the western and northern parts of the state could combine their interconnection applications and thus share costs on required upgrades. The grid operator could also analyze the combined interconnection requests in the same system impact study (SIS).

Interconnection Queue Backlog

ISO-NE has experienced a persistent backlog of interconnection requests in Northern and Western Maine, where several thousand megawatts of proposed resources have requested interconnection. In March, the RTO said it would not issue a competitive solicitation for the proposed Keene Road market efficiency transmission upgrade because the cost would be greater than the production savings. (See ISO-NE Nixes Keene Road Tx Upgrade.)

The proposed clustering methodology comprises two phases. In the first phase, the RTO will identify the initial designs of cluster-enabling transmission upgrades (CETU) in the regional system planning process. In the second phase, the RTO will conduct the cluster SIS to study the interconnection of the individual projects, together with the identified CETU.

New England is going to be looking at applying the clustering methodology to both AC and HVDC solutions. One speaker expressed concern that having two options would mean neither would reach critical mass, saying, “Sounds like you could have two undersubscribed” solutions.

Driven by the Wind

Wind resources looking to be included in such a cluster will have to join the transmission interconnection queue by about August. The study proposes that transmission owners prepare cost estimates by the PAC meeting in June, after which ISO-NE will calculate cost allocations and issue a draft report for comment.

As is currently the case, none of the shared or individual interconnection transmission upgrade and facility costs will be incorporated into regional transmission rates.

maine resource integration study ISO-NE — | *ISO-NE*

In June 2015, the American Wind Energy Association petitioned FERC to initiate a rulemaking process to address “complex, time-consuming technical disputes” in the interconnection queue process that “undermine the ability of new generators to compete.”

In response, FERC last December issued a Notice of Proposed Rulemaking that would change the pro forma large generator interconnection rules to increase certainty and transparency for new resources (RM17-8). (See FERC Proposes Changes to Interconnection Rules.)

New Circuits

The Maine Resource Integration Study assesses new 345-kV AC transmission circuits that could connect to the areas with the largest number of interconnection requests. Evaluations include interconnecting with, or bypassing, existing lines and substations.

The New England Power Pool Participants Committee in February supported Tariff changes for the proposed interconnection clustering methodology. Two or more interconnection requests requiring common new transmission infrastructure would trigger the clustering methodology.

Participants in a cluster would be allocated a percentage of costs for shared upgrades and assume sole responsibility for facilities needed solely for their project.

May 29, 2017January 17, 2024

ISO-NE: Lack of Fuel Could Idle Half of Gas Plants in Winter

By Michael Kuser

WESTBOROUGH, Mass. — New England will have only enough natural gas capacity to supply about half of its gas-fired generation in winters 2025 and 2030 in most scenarios, according to an analysis presented to the ISO-NE Planning Advisory Committee on Thursday.

Mark Babula, ISO-NE system planning manager for resource adequacy, said the study showed the region will have sufficient pipeline and LNG capacity to supply all the gas generation with capacity obligations during the summer. But in the winter — when generators must defer to firm gas heating customers — the region won’t have sufficient capacity under most circumstances to run all the gas generation that could be economically dispatched.

“When we’re talking about dispatch, what we’re looking at from the natural gas system perspective is meeting the contractual requirements to the [local distribution companies],” said Michael Henderson, ISO-NE director of regional planning and coordination. “That then gives you some extra gas available that can potentially serve natural gas-fired generation. It’s just different looks at how much natural gas-fired generation can be brought on.”

The ISO-NE study considered six natural gas system topologies and six “resource expansion” scenarios to determine whether there is sufficient “spare” gas for electric generation after meeting all firm customers’ needs:

Installed Capacity: All gas-fired generation with capacity supply obligations — a summer focus that represents the upper band of gas consumption by the electric sector. Even under the minimum gas infrastructure case, there is enough spare gas to fuel all gas-fired generation in the summers of 2025 and 2030, but there is only enough spare gas in the winters to serve about half of the gas-fired installed capacity.
Dispatched Capacity: Gas-fired dispatched capacity requirements on the winter peak gas day, when only a portion of installed gas capacity is needed to serve electric demand.
Energy Generation: Whether there is enough gas to satisfy the maximum hourly electric energy production by gas-fired generation on the summer and winter peak gas-days. The analysis found sufficient gas for all summer generation needs. For winter 2025, however, there would be sufficient gas for only 6.8 to 9.6 GW of generation, representing 42 to 59% of the projected installed capacity. By winter 2030, the gas could run between 5.3 and 10.1 GW — as little as one-third of the installed capacity.

Only one of six resource expansion scenarios (“Renewables Plus”) meets the dispatched capacity and energy generation requirements for winters 2025 and 2030, even assuming the “maximum gas infrastructure” — reflecting pipeline expansions, increased peak shaving by LDC, and LNG from offshore and ENGIE’s Distrigas terminal in Everett, Mass.

“In the summertime, we’re good. There’s actually leftover gas: We could actually run another 12,000 to 15,000 MW, there’s so much excess pipe available,” Babula said. “When you get into those polar vortex sort of days, we often hear from generators that have just been called by the gas pipe to get back on their ratable take and shut off the valve.”

Babula pointed out that the analysis studied only winter and summer peak days. ISO-NE is also conducting a Fuel Security Analysis that will quantify the operational risks of insufficient fuel for the entire 90-day winter period. ISO-NE on May 22 published a summary of the analysis, which is expected to be completed this fall.

While the RTO’s analysis looks at the system’s maximum, short-term capability, the ISO-NE study will determine how often the system likely to be stressed during the winter under different scenarios.

LNG’s Role

LNG from Distrigas, the Canaport terminal in Saint John, New Brunswick, and offshore floating storage regasification units are critical for meeting the peak gas-day requirements of the electric sector, according to the study. Without these gas supply sources, approximately ~1.5 Bcfd (~214,300 MWh/d) would be taken out the market.

Management consultant Richard Levitan asked whether the floating storage wouldn’t better be classified as a commodity, considering how inflexible the arrival of LNG carriers can be. Babula said that in the past couple years there have been “ships at the buoy” on most peak gas days, so they included them in the study.

[EDITOR’S NOTE: An earlier version of this article mistakenly said the analysis was conducted by the New England Power Pool. It was conducted by ISO-NE.]

Six Resource Expansion Scenarios

The resource expansion scenarios were:

- - S1 = RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas combined cycle units.
  - S2 = ISO Queue: Physically meet RPS and replace generator retirements with new renewables and clean energy.
  - S3 = Renewables Plus: The region retires older generating units, physically meets all state RPS and adds renewables/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage.
  - S4 = No Retirements (beyond FCA 10): Meet RPS with new resources under development and use alternative compliance payments (ACPs) for shortfalls. Add natural gas units.
  - S5 = ACPs + Gas: Meet RPS with new resources under development and use ACPs. Replace all retirements with natural gas units.
  - S6 = RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV.

May 29, 2017

MISO, PJM Weighing 8 Interregional Tx Proposals

By Amanda Durish Cook

MISO and PJM are evaluating eight proposed interregional market efficiency projects, but a supplemental project by American Electric Power could undermine most of the proposals.

MISO and PJM received three upgrade and five greenfield proposals for three congested flowgates ranging from $1 million to $198 million.

Proposals were due at the end of February on interregional projects for constraints MISO and PJM previously identified. (See “2017 MEP Identification Underway,” FERC Signals Bulk of NIPSCO Order Work Complete.)

interregional market efficiency projects miso pjm — Thoms | © *RTO Insider*

MISO and PJM will evaluate the proposals’ benefits based on the first 15 years of service, benefit-cost ratios and the cost split between RTOs, Eric Thoms, MISO manager of planning coordination, said at a May 23 Joint and Common Market meeting. AEP-Exelon, NextEra, Northern Indiana Public Service Co., AEP-NIPSCO, WPPI Energy and Northeast Transmission Development submitted proposals, most offering 138-kV projects and a few submitting 345-kV solutions.

All but two of the project proposals focus on the Olive–Bosserman constraint near the western Indiana-Michigan border. Transource Energy also submitted an interregional proposal to correct congestion along the southern Indiana-Ohio border with a new 138/345-kV substation and lines, and NIPSCO presented a new 138-kV line proposal to relieve congestion along the northern Illinois-Indiana border.

Complicating matters, AEP also announced plans for a supplemental project — a project type funded wholly by the transmission owner and therefore not requiring PJM approval — that diminishes the severity of the Olive–Bosserman constraint.

AEP would increase voltage and reroute nearby PJM circuits dating back to the 1930s, with two new 138/120-kV distribution stations to replace lower-voltage stations. The project is still in conceptual stages, AEP said.

PJM staff said the AEP project would relieve some of the congestion on Olive–Bosserman but that the interregional proposals could still provide benefits. MISO and PJM have yet to study the effects of the supplemental project on the six interregional proposals.

At a May 26 Interregional Planning Stakeholder Advisory Committee conference call, NIPSCO’s Miles Taylor asked if the supplemental project would be included in the RTOs’ evaluations of the interregional proposals. PJM interregional planning manager Chuck Liebold said PJM will put the project into a base case scenario if AEP decides to pursue the project. Stakeholders reminded RTO staff at the meeting that developers spent a lot of time and money on the interregional proposals, expressing concern that they could be negated by AEP’s project.

“This [supplemental] project is happening to get attention now because of its impact on interregional projects. We get many, many supplemental projects all the time,” said Liebold, adding that RTO staff has no control over which are built.

The RTOs hope to have preliminary benefit numbers on the interregional projects by the end of June.

Project evaluation will continue for each RTO individually and in the IPSAC through the end of September. Selection of the interregional projects is expected to begin in the fall.

Thoms said that if any projects arise out of the two-year interregional process, they will be sent before the RTOs’ boards for approval by December.

Meanwhile, MISO has asked FERC for an 18-month extension to settle on an internal cost allocation approach under the commission’s directive last year that the RTO allow interregional market efficiency projects as low as 100 kV (ER16-1969). Stemming from a 2013 NIPSCO complaint, FERC’s order also directed MISO to remove its $5 million cost floor for interregional projects with PJM. (See FERC Signals Bulk of NIPSCO Order Work Complete.)

May 29, 2017

PJM Kicks off Transmission Cost Cap Initiative

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM’s Planning Committee on Wednesday held its first special session on cost caps and other cost-containment provisions for competitive transmission bids. The RTO expects that any recommended procedure changes that are identified by the sessions will be incorporated in the new Manual 14F: Competitive Planning Process, which received its third “first” reading at the Markets and Reliability Committee meeting last week.

At the initial meeting, PJM provided several examples of cost-recovery and cost-containment mechanisms that have been proposed. Stakeholders indicated an interest in a standardized lexicon for cost-containment descriptions to aid in comparing project proposals.

Ruth Ann Price of the Delaware consumer advocate’s office urged keeping the process simple and argued for allowing very few exemptions to cost caps.

Sharon Segner of LS Power suggested that there’s a role in the discussion not only for FERC, whose Order 1000 opened up transmission development to competition, but also for the regional planning organizations to encourage cost containment proposals.

Following a technical conference in June reviewing the first five years under the order, the commission asked for comments in response to a series of questions on cost-containment provisions (AD16-18). (See FERC Calls for Post-Conference Comments on Order 1000.)

FERC asked for information on how transmission providers compare proposals with and without cost-containment provisions; whether it should provide guidance or requirements on the use of such provisions; suggestions for ensuring the transparency of evaluations; and whether there should be standardization of cost-containment provisions or exclusions of certain costs to facilitate comparison of proposals with differing containment provisions. The commission also asked what types of performance-based rates it could accept to reduce “asymmetrical risk.”

The next big question for PJM’s initiative is to determine if the focus should be on capital costs or annual revenue requirements. Stakeholders noted that PJM’s focus has historically been on capital costs.

cost-containment provisions PJM — | *PJM*

Through PJM’s 13 competitive windows since 2013, about 18% of 650 proposals included cost-containment provisions. Of those, two projects were selected.

Cost caps have been more common in other regions. Of 12 competitive windows including CAISO, SPP and MISO, 54% of the 56 proposed projects and 55% of the selected projects included cost-containment provisions.

The committee’s next special session is scheduled for July 18.

May 29, 2017

PURPA Critics Call for Reforms

By Robert Mullin

ANCHORAGE, Alaska — A nearly 40-year-old federal law enacted to spur competition in the power industry is badly outdated and in need of reforms to reflect the current markets, critics of the law said during a panel at the annual Western Conference of Public Service Commissioners last week.

annual Western Conference of Public Service Commissioners PURPA — Smutny | © *RTO Insider*

“I kind of feel like I was invited to lunch only to find out that I am the lunch,” joked Jan Smutny-Jones, CEO of the Independent Energy Producers Association, and the lone defender of the Public Utility Regulatory Policies Act on the panel.

The discussion was moderated by Idaho regulator Kristine Raper, whose commission has been an outspoken opponent of PURPA because of its impact on Idaho Power, which has faced mandatory purchase obligations equal to half its load. (See FERC Conference Debates PURPA Costs, Purchase Obligations.)

Before setting out his case against PURPA, Jonathan Weisgall, vice president of government relations at Berkshire Hathaway Energy, provided a brief history of the act.

Congress passed PURPA in 1978 in response to the mid-70s energy crisis, Weisgall pointed out. The law was designed to promote energy conservation and increased use of domestic energy resources, including cogeneration and renewables. It mandated that all electric utilities — including municipals and cooperatives — purchase electricity from “qualifying facilities” at the utility’s “avoided cost.” QFs were defined as cogenerating plants and small power producers — under 80 MW.

The Case Against PURPA

But the energy sector has “changed completely” in the 40 years since PURPA’s passage, according to Weisgall, and the law — including FERC’s regulations implementing it — have not kept up.

He recounted a litany of complaints over the law: Utilities are required to buy power that is neither necessary nor cheap, and they have no control over where QF projects are integrated into the system. PURPA contracts can be lengthy and are not subject to the same resource planning and cost scrutiny as other utility decisions, undermining state integrated resource planning and processes. QFs are not subject to the same curtailment procedures as other generators, yielding an unfair advantage.

“And, lastly, since QFs are not subject to resource planning … significant additions of unplanned renewable QFs can cause reliability issues if they don’t provide planned-for ancillary services,” Weisgall said. “So PURPA is simply outdated.”

Former FERC Commissioner Philip Moeller, now a senior vice president with Edison Electric Institute, concurred with Weisgall, calling PURPA “a relic of another era” and saying the country’s generation fleet has achieved the diversity envisioned by the act.

In 1978, Moeller pointed out, the U.S. produced more than 16% of its electricity from oil. “Now it’s down to 1%. The resource mix has changed dramatically.”

1992 Energy Policy Act

Both Moeller and Weisgall pointed to the 1992 Energy Policy Act as being the driver in transforming the market for generation in recent decades.

“FERC’s requirement of open access to transmission and standardized interconnection rules and procedures for smaller facilities have removed structural barriers to entry and opened up opportunities for new entrants, including QFs, to supply wholesale energy to distant markets whether a utility is a member of an RTO or not,” Weisgall contended.

“We now have better markets. We didn’t have RTOs then, or an EIM,” Moeller said, referring to the CAISO-run Western Energy Imbalance Market.

“Talking about EIM as a competitive alternative — QFs don’t participate in that market,” Smutny-Jones countered. “The reality is that I seriously doubt that there’s any utility in the West that would come to [a utility commission] and say, ‘Don’t worry about it, I’m going to cover the cost of my power plant in the EIM market.’ This isn’t going to happen.”

Smutny-Jones, whose organization represents independent power marketers and generators in California, agreed that “PURPA has been with us for a while.” Like other energy rules, it could be “fine-tuned from time to time.”

“But I think it has usefulness, I think it will continue to have usefulness to push where we don’t have some competitive pressure on vertically integrated utilities,” he said.

Moeller pointed to another reason to roll back PURPA’s purchase obligations: the success of energy efficiency measures.

“We have flat to declining load growth in electricity, something that was unfathomable for decades and decades and decades,” he said. “Modern reality comes down to … in many cases, utilities are required to buy power they just don’t need in a flat or declining demand situation.”

On top of that, Moeller argued, utilities are often paying above-market prices.

“When you add to the cost of power and customers have to pick that up, it has a reverse impact [on efficiency]. Take a look at the Northwest: The No. 1 resource for the Northwest Power Pool for 25 years has been efficiency. That is their first choice,” he said.

Smutny-Jones questioned the premise that declining load should be cited as a reason to roll back PURPA.

“If I heard my colleagues correctly, you should all be seeing [integrated resource plans] coming before you that show no new builds ever in the West. I don’t think that’s true,” he said. “I don’t pretend to have read the IRPs in 13 western states, but I guess that there will be a significant amount of build-out of different kinds of generation over the next 10 years or so, and that should be subject to pressure from PURPA.”

‘More Tools, not more Constraints’

Weisgall laid out a series of recommended changes.

Among them: Congress should modify the purchase obligation to clarify that states that utilize IRPs have the authority to decide whether their utilities are obligated to purchase from QFs. In addition, Congress should reduce the size of QFs to “well below” 80 MW and modify FERC’s “1-mile rule” in order to prevent suppliers from disaggregating their projects “to essentially game the system.”

The 80-MW threshold applies to all generating facilities at the “same site” — which FERC has defined as all facilities within 1 mile of the facility seeking QF status. Weisgall said Congress should redefine “comparable markets” to relieve utilities participating in voluntary auction-based and energy imbalance markets from the mandatory purchase obligation.

Weisgall also thinks state commissions should exercise more discretion on the length of PURPA contracts and avoided-cost calculations to ensure those costs are no higher than competitive wholesale market prices — citing LMPs and auctions as potential proxies.

“States need more tools, not more constraints,” he said.

Smutny-Jones acknowledged that his state of California made some mistakes early on in its adoption of PURPA when it set avoided costs based on oil at about $100 a barrel.

“We learned from that,” he said, adding that in the early 1990s California created a system in which utilities put out a hypothetical generating resource that suppliers could bid against.

“And it was hugely successful,” Smutny-Jones said. “The prices were significantly lower than what the utilities had suggested they would be.”

“There’s a lot of power in the states to try to modify PURPA in ways that can work for you,” he said, addressing regulators in the audience.

Smutny-Jones noted that the avoided-cost formulation falls to state regulators.

“So you can either count on the market to give you that number and have people compete against each other, or you can try to come up with a complicated formula,” he said. “I would have to caution you about that latter [option] because you’ll get it wrong,” he said.

Why ‘Avoided’ Costs?

Weisgall said Smutny-Jones had raised “an interesting point of history.”

“Why did PURPA use the term ‘avoided costs?’ Because there were no market prices. There were no markets as such, so that was the formula, and today of course there are market prices, but we have still have to worry about what avoided cost means, which has kept generations of lawyers employed.”

Weisgall posed a question about states that allow third-party suppliers “complete access” to the transmission system.

“Why do they need PURPA if you’ve got a solar farm and it’s a great one and its [cost is] below what the utility could build? We’re already seeing with our NV Energy utility in Nevada that we are losing some major customers — casinos — where they are finding third-party providers. Well why do we need PURPA under those circumstances?”

Smutny-Jones acknowledged that PURPA is no longer an issue in California because the state’s aggressive renewable portfolio standard has created a strong market for third-party generation. “My phone hasn’t rung off the hook about PURPA for a very, very long time because people have other places to go with their resources,” he said.

Moeller wrapped up the discussion with a call to arms directed at his former agency rather than the state commissioners in attendance.

“I don’t think I’m overstating a full-blown crisis when a utility in Idaho that’s guaranteed [to be] long power until at least 2035 is being required to buy at the cost of … $3.1 billion over the next the next 20 years … for power they don’t need.

“That’s pretty serious. So I think a newly rebooted FERC will have to address this.”

May 29, 2017

ISO-NE Planning Advisory Committee Briefs

WESTBOROUGH, Mass. — ISO-NE’s 2017 Economic Study will reflect the same basic assumptions and use the same profiles as those in the 2016 study, while representing some incremental changes to the former study’s third scenario. Marianne Perben, manager of resource adequacy and technical studies, outlined the 2017 study’s scope of work to the Planning Advisory Committee on Thursday, saying it will produce metrics similar to those in the 2016 report being completed now.

The 2017 study will include analysis that the Conservation Law Foundation requested at the April PAC meeting. The CLF wants the grid operator to determine whether there are viable system topologies other than those analyzed in Scenario 3 of the 2016 study with similar total system emissions but a lower relative annual resource cost.

Strong Mass. Economy Nudges up 2017 CELT Load Forecast

The 2017 Capacity, Energy, Loads and Transmission Report shows a reduced RTO load forecast from 2016 but predicts an increase in load for the Southeast New England area because the Massachusetts economy is growing faster than those in other New England states.

ISO-NE system planner Manasa Kotha on Wednesday presented a report on future capacity requirements, which credited some of the increase to changes in the operating company distribution of the load to the buses, and some to the Massachusetts economy, which is expected to grow at a compound annual growth rate of 2.1% through the forecast horizon.

The report covers net installed capacity requirements (ICR) for capacity commitment periods 2022/23 through 2026/27, ranging from 34,300 MW in the first cycle covered to 35,700 MW in the last.

ISO-NE planning advisory committee load forecast — | *ISO-NE*

The load forecast is net of behind-the-meter solar PV resources. Energy efficiency is treated separately — modeled as a supply-side capacity resource in the ICR calculations.

For additional background, Kotha referred participants to a Reliability Committee presentation on the ICR Values for CCP 2020/21 covered by Forward Capacity Auction 11.

Locational Reserves Good in Key Load Centers

Generation and transmission additions expected to be completed by 2019 will ensure sufficient operating reserves in Greater Boston, Greater Connecticut and Greater Southwest Connecticut through 2021, according to a report on reserve needs for major import areas.

Forward reserve requirements for the Northeast Massachusetts/Boston zone have ranged from 300 to 500 MW for the last three summers, and 0 MW for the winters. The report calls for 279 MW this summer and 200 to 650 MW for 2018, dropping to 0 to 50 MW after the addition of the 674-MW Footprint Power quick-start combined cycle plant at Salem Harbor, which is expected online by the end of the year.

ISO-NE resource adequacy planner Fei Zeng, who presented the report to the PAC on Wednesday, said that fast-start resources near those major load centers provide flexibility to the grid.

— Michael Kuser

May 29, 2017

Study: New Resources Could ‘Crowd Out’ Old in ISO-NE

By Michael Kuser

WESTBOROUGH, Mass. — A substantial increase in new clean resources would lower Forward Capacity Auction prices, “crowding out” many existing resources — but their ability to do so will depend on the level of offer mitigation, according to an analysis commissioned by ISO-NE.

ISO-NE last year asked Analysis Group to assess outcomes in the Forward Capacity Market under six resource expansion scenarios evaluated in the second part of the 2016 Economic Study. (See scenario descriptions below.)

Todd Schatzki of Analysis Group briefed the Planning Advisory Committee on Thursday on the study, which assumes all current market rules. The study assumes retirements of 2,457 MW by 2025 and 4,668 MW by 2030. Absent retirements, Schatzki said, there’s limited need for new resources.

“Given low load growth, given what’s going on behind the meter and given that there is not necessarily a lot in the queue that is coming in, absent some market price signal, you’re not going to get new resources coming in,” said Schatzki, who prepared the report with colleague Christopher Llop. “You’re not going to get prices raising back up towards the cost of new entry unless some new resources get in the system.”

Capacity and Energy Market Implications

Total Forward Capacity Market payments in 2025 are projected to range between $2.1 billion in Scenario 3 (“Renewables Plus”) to $3.8 billion in Scenarios 2 (“ISO Queue”) and 6 (“RPS + Geodiverse Renewables”), with energy market revenues projected between $7.7 billion and $8.8 billion.

resource expansion scenarios ISO-NE — | *Analysis Group*

Scenarios with renewable additions would require additional revenue streams from outside the ISO-NE markets because they have a higher cost of new entry, the study says. Substantial expansion of clean resources as in Scenario 3 “would lower FCA prices, crowding out existing resources.”

“As the quantity of new clean resources added to the system increases, the cost (per MWh or MW) of supporting clean resources increases. The gap in revenue requirement (for new entry) needs to be filled by other sources because of decreases in revenues from both the FCM and energy markets.”

These impacts would depend on what portion of new renewables participate in the capacity auction and the extent of offer mitigation under the minimum offer price rule. The study assumes continuation of the current 200 MW/year renewable exemption, evaluating mitigation levels through sensitivity analyses.

Under four of the scenarios (1, 2, 5 and 6), the combination of energy, ancillary services and capacity revenue is sufficient to support the entry of new gas-fired combustion turbines. But market revenues are insufficient to incent the development of all other new resources assumed to enter the market in each scenario and none of the scenarios provides sufficient revenues for new combined cycle plants.

“Clean” resources — including offshore wind, hydro imports, battery storage and behind-the-meter solar, — would require other revenues, such as state renewable portfolio standards. “Needed revenues increase with the expansion of clean resources, as these resources reduce prices in both the energy and capacity markets,” the study says.

Total payments in the ISO-NE markets range from $9.7 billion to $15.6 billion, excluding ancillary service payments. The total payments do not include the costs associated with state policies.

ISO-NE completed Phase I of the Economic Study earlier this year and in June will issue the final part.
Robert Ethier, vice president of market operations, outlined the scope of work and for background information referred participants to a study on Forward Capacity Auction results published in December 2016.

Six Resource Expansion Scenarios

The resource expansion scenarios were:

S1 = RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas combined cycle units.
S2 = ISO Queue: Physically meet RPS and replace generator retirements with new renewables and clean energy.
S3 = Renewables Plus: The region retires older generating units, physically meets all state RPS and adds renewables/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage.
S4 = No Retirements (beyond FCA 10): Meet RPS with new resources under development and use alternative compliance payments (ACPs) for shortfalls. Add natural gas units.
S5 = ACPs + Gas: Meet RPS with new resources under development and use ACPs. Replace all retirements with natural gas units.
S6 = RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV.