Page 1204 – RTO Insider

March 2, 2018

FERC Greenlights Great Plains-Westar Merger

By Amanda Durish Cook

FERC on Wednesday approved the proposed $14 billion merger between Great Plains Energy and Westar Energy, ruling that it would not have an adverse impact on market competition or rates in SPP.

The deal is still subject to approval by Kansas and Missouri regulators.

Missouri-based Great Plains owns Kansas City Power & Light, and Kansas-based Westar owns Kansas Gas and Electric. Kansas regulators last year pushed back on Great Plains’ original plan to buy out Westar, spurring the companies to recast the transaction as a “merger of equals.”

Under a revised plan filed with the Kansas Corporation Commission in late August, Great Plains proposed that the two companies would combine under a $14 billion holding company operating in both Kansas and Missouri. Westar shareholders would own about 52.5% of the company with Great Plains shareholders holding the rest, according to the amended merger application (18-KCPE-095-MER). The companies have pledged that the holding company will maintain separate debt and capital structures for each subsidiary. (See Great Plains, Westar File Revised Merger Plan.)

The deal would entail no cash exchange or transaction debt, and retail customers would receive $50 million in upfront bill credits across all rate jurisdictions. The combined company would serve about 1 million customers in Kansas and almost 600,000 customers in Missouri.

In approving the deal, FERC made clear that a five-year hold-harmless commitment agreed to by the two companies would not cover any costs related to Great Plains’ failed bid to buy out Westar (EC17-171). Under that commitment, Great Plains and Westar have agreed not to seek to recover any costs related to integrating the companies unless they can demonstrate, through a Section 205 filing, that a merger activity yielded savings in excess of costs incurred.

Greta Plains Energy Westar Energy merger SPP — | *Great Plains and Westar*

But the commission clarified that because Great Plains’ original acquisition strategy was “pursued but never completed,” costs related to the transaction “should not be included as part of the hold-harmless commitment and cannot be recovered from ratepayers pursuant to it. The costs related to the 2016 transaction are instead subject to the commission’s ordinary ratemaking principles under [Federal Power Act] Sections 205 and 206.”

Additionally, FERC said it was not persuaded by a protest by Kansas Electric Power Cooperative, which asked the commission to apply an equally strong hold-harmless commitment to wholesale customers as it would for retail customers, using pre-merger common equity levels to calculate rates, shielding the co-op from merger-based rate impacts. It also asked that all hold-harmless commitments be indefinite.

FERC said ordering extra hold-harmless protections without evidence would be “speculative” and noted that it doesn’t require merger plans to include hold-harmless commitments for market-based wholesale power sales.

The commission also declined the co-op’s request that Great Plains and Westar provide it with a detailed list of all merger-related costs through a new compliance filing.

The proposed merger is still in prehearing stages at the KCC until March 19, when the first evidentiary hearing is scheduled. A public comment period on the merger ends March 29.

The Missouri Public Service Commission is also reviewing the proposed merger and will hold evidentiary hearings March 12 to 16 (EM-2018-0012).

March 2, 2018

ERCOT: Tight Summer Margins No Cause for Alarm

By Tom Kleckner

ERCOT said Thursday it expects the recent retirement of coal-fired and aging units to result in tight operating reserves this summer — an unnerving proposition for some observers when the ISO is also projecting record-breaking peaks during the summer heat.

According to ERCOT’s preliminary seasonal assessment of resource adequacy (SARA) for the summer (June-September), the grid operator expects a total resource capacity of 77.7 GW. That doesn’t leave much wiggle room when the report also forecasts a summer peak load of almost 73 GW, which would break the 2016 record of 71.1 GW.

“The name of the game is performance,” ERCOT Manager of Resource Adequacy Pete Warnken said during a media call, repeating a message CEO Bill Magness delivered to the ISO’s Board of Directors last week. “We need to make sure all our resources are available and that we have situational awareness. If everyone is diligent about doing their job, we should be fine.”

ERCOT ORDC operating reserves — ERCOT operators monitor the Texas grid. | © *RTO Insider*

Warnken highlighted ERCOT’s operating reserve demand curve (ORDC), a real-time price adder that reflects the value of available reserves, as one of several pricing mechanisms available for use this summer. He said the ISO will be “centrally testing” the ORDC for the first time this summer.

Dan Woodfin, ERCOT’s senior director of system operations, joined with Warnken in explaining to anxious Texas media how emergency response and other ancillary services, demand response, the 1.2 GW of emergency capacity available over five DC ties, and the availability of generators that can switch between neighboring grids will help prevent rolling blackouts in a worst-case scenario.

“We certainly have the tools and processes in place,” said Warnken, who also dismissed the likelihood of blackouts.

“In general, the whole market is set up in such a way that it encourages all generators to be online and resources to be available,” Woodfin said. “During these tight conditions, when prices are higher, there are lots of economic incentives to reduce demand or produce power.”

ERCOT said in its SARA announcement that the wholesale market provides “strong financial incentives” for generators to be available when demand rises and for retail electric providers to prepare for price fluctuations. It also raised the possibility of voluntary load reductions and injections of energy into the market by industrial facilities during peak demand.

In a somewhat unusual move, the Public Utility Commission of Texas, which oversees ERCOT, issued a statement following the SARA release, saying it continues to “closely monitor” this summer’s supply and demand forecasts. It noted generation owners’ decisions to retire large coal-fired power plants have “significantly reduced the excess supply of electricity” ERCOT has “enjoyed over the past five years.”

“It is important to note that the ERCOT market is designed with a number of mechanisms and tools to incentivize increases in supply or temporary reductions in demand to maintain the reliability of the system,” PUC spokesman Mike Hoke said, referring to the many different tools at the ISO’s disposal.

ERCOT attributed the tightening operating reserves to increased load from the state’s strong economy and the recent retirements. In a statement, Magness noted a series of monthly, winter and all-time peak demand records during recent years “as Texas’ economy continues to grow at record pace.”

“We expect high demand will continue this summer,” he said.

The ISO’s year-end Capacity, Demand and Reserves (CDR) report projected a 9.3% planning reserve margin for 2018, half of what it was in May and 4 percentage points below a 13.75% target ERCOT established for itself in 2010, following the wave of plant retirements last year. (See ERCOT: Tightening Reserve Margins no Cause for Concern.)

ERCOT said 3,800 MW in new generation resources began operating in 2017 and more than 14,000 MW of resources are planned to be in service by 2020.

The ISO also released its final assessment for the spring season (March-May), adjusting its spring peak forecast to 59.5 GW. It said it has sufficient generation on hand to meet demand.

March 2, 2018May 31, 2024

NRG Announces $1 Billion Stock Buyback, $70 Million Sale

By Peter Key

NRG Energy said Thursday that its board has authorized the company to spend $1 billion to repurchase its own shares.

The company also said it has agreed to sell its Boston Energy Trading and Marketing subsidiary to Mitsubishi’s Diamond Generating unit for $70 million.

The moves are the latest in a series of steps NRG has taken to boost its share price in response to pressure from Elliott Management, a hedge fund run by billionaire Paul Singer, and Bluescape Energy Partners, a private investment firm, which announced in January 2017 that they had taken a 9.4% stake in the company.

NRG last July announced a transformation plan that it said would improve its recurring costs and margins by $1.1 billion; raise from $2.5 billion to $4 billion in cash through asset sales; and remove $13 billion in debt from its balance sheet. The company took major steps to execute that plan last month when it agreed to sell its renewables business, its stake in NRG Yield and its South Central Generating subsidiary in transactions that will bring it $2.8 billion in cash and take $7 billion in debt off its books.

The company also said last month that it expects to announce more sales this year and has revised its total asset sales cash proceeds target under the transformation plan to $3.2 billion. (See NRG Selling Renewables, Other Assets for $2.8 Billion.) With the announcement of the Boston Energy sale, the company has reported sales totaling more than $3 billion, all of which are on track to close by the end of the year, CEO Mauricio Gutierrez said during the company’s earnings call Thursday. As the closings progress and NRG completes the initial $500 million portion of its share repurchase program, it will look to kick off the second $500 million round of buybacks, he said.

Gutierrez also said NRG’s GenOn Energy subsidiary, which is operating under bankruptcy protection, could transition to becoming a standalone company as early as September. GenOn’s reorganization plan was approved by the U.S. Bankruptcy Court in Delaware in December, and its financial results are no longer included in NRG’s. On Tuesday, Platinum Equity said it has agreed to buy an 810-MW combined cycle gas-fired plant in Gettysburg, Pa., from GenOn for $520 million.

NRG posted a loss of $1.67 billion from continuing operations on revenue of $2.46 billion in the fourth quarter of 2017, compared to a loss of $891 million on revenue of $2.48 billion in the same quarter of 2016.

March 2, 2018

MISO Wins Delay on 5-Minute Settlement Roll-Out

MISO on Wednesday secured another four months to implement mandatory five-minute market settlements, providing its staff more time to roll out new software designed to manage the process.

FERC granted MISO’s request to delay implementation from March 1 to July 1 after the RTO said it requires “more time to develop and test the software, after which market participants need a minimum of three months to make corresponding adjustments to their own software and reporting systems” (ER18-314).

MISO FERC five-minute settlements — MISO’s Carmel. Indiana Control Room in 2013 | *MISO*

The decision marks the second time the commission has extended the deadline for instituting five-minute settlements, required under FERC Order 825. MISO last May won an initial extension from Jan. 11 to March 1, but late last year multiple stakeholders noted that delays in replacing the RTO’s overall settlements system would result in members rushing to adapt their own systems to accommodate the new process. (See “MISO Asks for 5-Minute Settlement Delay,” 8 Projects Set for 2018 MISO Market Roadmap.)

FERC determined that MISO’s request for more time was made in good faith and was necessary for software testing.

“We find that good cause exists to grant this extension because of the importance of ensuring that software and testing requirements are met for both MISO and its market participants. … This extension will facilitate a smoother and more effective implementation of five-minute settlements in MISO,” the commission said.

In February, MISO staff said the RTO is still on track for fully functional testing with stakeholders beginning April 1, with the new settlements computer system fully implemented by April 16.

— Amanda Durish Cook

March 2, 2018

NYISO Management Committee Briefs: Feb. 28, 2018

RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved proposed rule revisions that would allocate day-ahead market congestion rent shortfalls and surpluses stemming from changes in transmission availability to the responsible transmission owner.

The measure, which would revise Attachment N of the ISO’s Tariff, will go to the Board of Directors for approval before a filing with FERC. The Business Issues Committee (BIC) recommended the proposal to the MC. (See “Day-Ahead Market Congestion Settlements,” NYISO Business Issues Committee Briefs: Feb. 14, 2018.)

At the Feb. 28 MC meeting, Operations Analysis and Services Supervisor Tolu Dina explained that the ISO’s proposed cost allocation methodology employs a de minimis threshold to determine when TOs are not allocated costs. The threshold applies to day-ahead constraint residuals less than $5,000, provided the sum of all such residuals falling below the threshold is not more than $250,000 or 5% of the sum of all day-ahead constraint residuals for the month.

Alternative Methods for Determining LCRs

The MC approved Tariff revisions to establish an alternative method for calculating locational minimum installed capacity requirements.

The revisions incorporate incremental changes recommended by stakeholders at the Feb. 6 Installed Capacity Working Group/Market Issues Working Group meeting, said Zachary Stines, NYISO associate market design specialist. (See “Alternative Methods for Determining LCRs,” NYISO Business Issues Committee Briefs: Feb. 14, 2018.)

Stines presented the new method for determining locational capacity requirements (LCRs) for localities, designed to minimize the total cost of capacity at the level of excess condition while meeting reliability criterion, maintain the installed reserve margin approved by the New York State Reliability Council and not exceed transmission security limits.

NYISO day-ahead market congestion — | *NYISO*

The ISO plan evaluates net energy and ancillary services revenue at different levels of installed capacity using data from the most recent of either the capability year after a quadrennial “demand curve reset” or the annual installed capacity update.

The Long Island Power Authority, NRG Energy and other stakeholders recommended sending the measure back to a working group for additional analysis. But other market participants countered that while a case can always be made for more analysis in a big project, the proposal — while imperfect — represents an improved approach for estimating requirements.

MC Rejects On Ramp/Off Ramp Changes

The MC rejected a market design proposal and related Tariff revisions that would have eliminated localities and revised the existing on ramp/off ramp rules to create a new locality.

The BIC rejected the same proposal on Feb. 14. (See “BIC Rejects On Ramp/Off Ramp Changes,” NYISO Business Issues Committee Briefs: Feb. 14, 2018.)

Zach T. Smith, NYISO manager of capacity market design, told the MC the proposed methodology is based on reliability planning principles developed to determine whether to create and eliminate localities.

The unique geographic nature of Zones J and K, encompassing New York City and Long Island, makes it difficult to site generation in those areas, which also confront distinct environmental issues, Smith said.

Mark Younger of Hudson Energy Economics reiterated the objections he made at the BIC meeting earlier in the month, calling the market design proposal — and NYISO’s review process — “flawed.”

BIC Chair Erin Hogan said NYISO received about 10 letters of support for the capacity market design from members of the public, the first time she recalled such a response. The letters will be posted on the ISO’s website.

— Michael Kuser

March 2, 2018

MISO, SPP Look to Ease Interregional Project Criteria

By Amanda Durish Cook

MISO and SPP are ready to reform their interregional planning process to improve their shot at producing their first cross-border transmission project, but they plan to wait a year before launching a joint study to identify such a project, the RTOs said Tuesday.

At a Feb. 27 MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting, the RTOs admitted that criteria spelled out in their joint operating agreement might be preventing beneficial interregional projects from gaining approval. They said they are ready to work with stakeholders through the summer to ease some restrictions.

SPP’s Adam Bell reviews lessons learned from previous IPSAC studies. | © *RTO Insider*

SPP Interregional Coordinator Adam Bell said the RTOs’ latest coordinated system plan study, concluded in 2017, showed they are still inconsistent in how they calculate adjusted production costs, develop regional models and review regional project proposals. Before being approved, proposed interregional projects must clear separate regional reviews by each RTO in addition to passing a joint review.

The RTOs have failed to approve an interregional project despite having conducted two coordinated system plan studies, although they have examined several candidate projects. (See MISO Confident in Tx Process with SPP Despite Lack of Projects.)

“We’ve learned a lot in both coordinated plans we’ve done,” Bell said. “Both SPP and MISO are interested in doing meaningful planning between our systems, and we want stakeholders to have faith in the process and feel good entering these studies. … Both RTOs support … designing a new study process that has stakeholder confidence. We’ve done this twice. Let’s fix this thing.”

MISO SPP IPSAC coordinated system plan — MISO’s Davey Lopez explains the IPSAC’s processes. | © *RTO Insider*

Davey Lopez, MISO adviser of planning coordination and strategy, said the RTOs plan to collect stakeholder suggestions and do more research before returning to the IPSAC in May with recommendations on how to improve their joint planning. The RTOs plan to work with stakeholders through September to prepare a FERC filing to alter their JOA by the end of the year.

Comprising planning staff from both RTOs, the Joint Planning Committee will vote later this year on whether to pursue another coordinated system plan.

Staff from both RTOs cautioned that they were unlikely to develop a 2018/19 study because planners are inclined to concentrate fully on process improvements, but stakeholders will be provided a non-binding IPSAC vote on where planners should concentrate their efforts.

$5 Million Obstacle

SPP and MISO said a major piece of the overhaul would be lowering the RTOs’ $5 million cost threshold for interregional projects.

“Hopefully, we can remove some of these hurdles on the coordinated system plan,” Lopez said.

In response to a question by Entergy’s Yarrow Etheredge, MISO and SPP staff declined to identify any specific project they would have liked to see pass but for the RTOs’ stringent criteria, although Lopez noted a few instances in which lowering the $5 million threshold would have improved a project’s chances in the last coordinated system plan.

“We really finished one study and started another, so we didn’t have time to implement these improvements we identified,” Bell said, referring to the short gap between the 2014/15 and 2016/17 studies. At the time, MISO recommended awaiting a second coordinated study while the RTOs worked out differences between their planning processes, but MISO eventually abandoned the idea in favor of starting another study.

Bell said it’s imperative for the RTOs to align their adjusted production costs and more accurately model each other’s systems. He suggested removing MISO and SPP’s joint modeling efforts altogether in favor of working on more identical regional models. Several stakeholders objected to that idea, claiming it could complicate cost allocation between the RTOs. Bell pointed out that MISO and SPP would still have a joint study under his plan, just not a joint model.

The RTOs are additionally contemplating allowing for adjustments in modeling cost allocation to determine if the benefits of a project are amplified.

SPP also continues to support cost allocation for sub-345-kV interregional projects with MISO, Bell said, a subject that MISO continues to discuss, according to Lopez. MISO has proposed cost allocation changes for its market efficiency projects, including a sub-345-kV cost allocation and elimination of a footprint-wide postage stamp rate. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.)

Entergy Critical of MISO-SPP TMEP

Entergy engineer Kyle Watson said the MISO-SPP seam does not yet have a structured enough coordination process to develop smaller interregional projects, such as those eligible to qualify under the new MISO-PJM targeted market efficiency project (TMEP) category, which relies on historical congestion to identify small transmission projects. MISO and PJM approved a $20 million, five-project TMEP portfolio late last year, representing the first interregional transmission projects between the two RTOs, and some stakeholders have called for a similar process on the MISO-SPP seam. (See MISO Board Approves $2.6B Transmission Spending Package.)

The MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) listens to Entergy’s Kyle Watson | © *RTO Insider*

Entergy’s Matt Brown said there isn’t sufficient operational data since the integration of the company into MISO and the Western Area Power Administration into SPP to build a case for congestion-relieving projects. But SPP Director of Seams and Market Design David Kelley disagreed, saying MISO and SPP have already collected enough historical congestion data to justify projects that are less costly than continuing to pay market-to-market congestion charges.

“The day-ahead and real-time congestion is persisting,” agreed Lopez.

During the IPSAC meeting, the RTOs pointed out that one congested flowgate on the Oklahoma-Kansas border has been responsible for nearly $20 million M2M payments since February 2017.

Wind on the Wires’ Natalie McIntire and WPPI Energy’s Steve Leovy said their organizations are displeased that the RTOs are not inclined to begin another coordinated system plan this year, given that the 2016/17 plan focused narrowly on needs along SPP’s Integrated System in North Dakota, South Dakota and Iowa, and the larger SPP-MISO seam has areas of congestion.

“There’s a lot of consumers bearing costs because we’re not fixing these issues,” Leovy said. “There’s need for a major interregional study.”

“We’re not happy, but we recognize there’s general consensus beyond us,” McIntire said.

March 1, 2018

Peak Touts ‘Independent’ Western Market Plan

By Jason Fordney

Peak Reliability and PJM officials on Tuesday promoted the independent and self-governing nature of their proposed Western energy market in an attempt to differentiate the effort from a competing initiative by CAISO.

“Our blank state for market governance really resonates with people, because they see they don’t have to inherit a governance structure from one entity or be burdened by a structure that is tied to a particular state,” Pete Hoelscher, Peak’s chief strategy officer, said during a Feb. 27 conference call.

Peak officials provided more details on the proposed market, along with feedback they have received from industry participants.

One major concern among participants interested in the market: getting the full and appropriate value for generation and transmission assets “because that is not happening in all cases today,” Hoelscher added.

In a parallel development, CAISO earlier this year announced a plan to bring day-ahead functions into its Western Energy Imbalance Market (EIM). (See Calif. Lawmakers Relaunch CAISO Regionalization.)

While Peak officials have previously said they aren’t setting out to create an RTO, the organization said Tuesday that its proposal is a pathway to developing one. Peak expects to publish a business plan on March 30 and hopes that by mid-April interested parties will enter into nonbinding agreements to assist in market governance and design. Binding agreements are targeted for June, and the goal is to have the market go live in June 2020.

Peak said that potential participants in the new market have expressed doubt that it can be operational by the scheduled target date of mid-2020 because of technical, operational and regulatory tasks, but Peak officials are stressing the operational experience of PJM, which operates a 13-state eastern energy market.

Other commenters to Peak noted that they have already invested in joining the EIM and are receiving financial benefits from the real-time balancing market. Some have told Peak that CAISO’s proposed day-ahead market across the EIM seems like the only foreseeable next step in developing a Western market. Others say the West needs more fuel diversity and participation, according to a Peak presentation.

peak reliability western energy market pjm — | *PJM Connext, Peak Reliability*

Based on feedback, Peak’s services would not include a capacity market, consolidation of open access transmission tariffs, or regional/sub-regional system planning for reliability, operational performance, public policy, market efficiency or interconnection.

Peak and PJM Connext announced their joint effort to develop a market in January. Visualized for day one is reliability coordination services, real-time and day-ahead energy markets, financial transmission rights allocation, balancing authority services, market monitoring and a self-governance model. (See Peak, PJM Pitch ‘Marketplace for the West’.)

March 1, 2018

FERC Rejects MISO Pseudo-Tie Pro Forma

By Amanda Durish Cook

FERC on Tuesday rejected MISO’s proposed pro forma agreement for pseudo-tying generation into PJM, saying the rules around termination were too broad.

“Although we believe that a pro forma pseudo-tie agreement is a beneficial instrument to promote uniformity, transparency and certainty as to what the responsibilities and obligations are with respect to the increasing interest to use pseudo-tie arrangements, we find that parts of the MISO agreement have not been shown to be just and reasonable,” FERC said in its order (ER17-1061).

The commission encouraged MISO to file a revised version.

In rejecting the agreement, FERC said MISO’s proposed termination provisions did not align with already accepted revisions to the MISO-PJM joint operating agreement. (See FERC OKs Change to MISO, PJM Pseudo-Tie Rules.) The agreement was unclear about the meaning and consequences of a suspension, FERC said.

MISO FERC pseudo-tie pro forma — | *MISO, PJM*

“The MISO agreement does not detail what happens to resources under suspension, how a resource may seek to resume normal operations, which balancing authority retains operational control of the resource while it is under suspension, or how a resource under suspension may be terminated,” FERC said.

The commission called the termination provisions “vague and open-ended.” While MISO proposed to give itself authority to “make all final determinations whether to implement or terminate [a] pseudo-tie,” FERC interpreted that language as granting the RTO the ability to terminate a pseudo-tie for any reason, provided it satisfied the six-months’ notice requirement.

The proposed agreement would have allowed MISO to suspend and terminate pseudo-ties if resource owners failed to provide real-time measurement values in a timely manner; if the generation-to-load distribution factor between MISO and PJM was not within 2%; and if a partially pseudo-tied resource injected more energy into MISO than the modeled limit.

MISO also proposed that a pseudo-tie maintain firm transmission service from source to sink for the life of the pseudo-tie, and that it could terminate a pseudo-tie if reliability is threatened, with no notice beyond compliance with NERC standards. However, the RTO proposed that its pro forma requirements would not be retroactively applied to existing pseudo-ties, provided that those existing pseudo-ties aren’t modified. In the event of a modification, MISO would restudy the pseudo-tie.

The rejected proposal was the subject of a deficiency letter last year in which FERC questioned under what circumstances MISO could revoke a pseudo-tie. (See MISO, PJM Respond to FERC’s Pseudo-Tie Questions.)

FERC’s ruling also dismissed as moot a protest and rehearing request by the Illinois Municipal Electric Agency, which had complained that MISO’s proposal threatened the vested rights of market participants with long-term historic generation and transmission rights to serve load. The agency argued that MISO could terminate its long-term, fixed transmission rights at any time and that the proposed 2% distribution load provision “suffers from a lack of transparency because modeling upon which this provision is based is complex and, for the most part, confidential” between PJM and MISO.

IMEA also contended the agreement should be between MISO, PJM and the pseudo-tie owner, rather than just MISO and the owner.

MISO Reaction; IMM Reliability Suspicions

MISO briefly addressed FERC’s rejection during a Feb. 28 MISO-PJM Joint and Common Market meeting, saying it intends to file again.

“MISO feels that the circumstances surrounding that agreement still exist, and the agreement is still needed,” Director of Market Design Kevin Vannoy told meeting attendees. The RTO plans to return to the Reliability Subcommittee sometime in spring to revise the agreement with stakeholders.

MISO and PJM staff at the meeting also noted they have reliably administered a considerable increase in pseudo-ties since the start of the 2016/17 planning year. MISO says its total pseudo-tied volume increased from 1,966 MW in June 2015 to 5,668 MW in June 2016.

But MISO’s Independent Market Monitor challenged the RTOs’ assertion that pseudo-tied generation has operated reliably.

IMM staffer Michael Wander asked if either RTO could deny that they’ve experienced control room “emergencies” as a result of poorly managed pseudo-ties, but both Vannoy and PJM officials said they didn’t understand the question and would not answer it.

“Let me rephrase. Would you say there haven’t been any extraordinary actions taken?” Wander asked. “Because when you say you’ve implemented those reliably, that means business as usual, but that’s not what I’m hearing from reliability coordinators.”

MISO and PJM staff denied that pseudo-ties have affected reliability.

Wander ended the exchange by saying he would provide RTO leaders with confidential pseudo-tie data that have been troubling the Monitor. Staff agreed they could hold a later discussion on the matter.

March 1, 2018

Van Welie: ISO-NE in ‘Race’ to Replace Retirements

By Michael Kuser

ISO-NE is “in a race” to relieve natural gas pipelines constraints and interconnect new generation before New England loses older, uneconomic resources, CEO Gordon van Welie said Tuesday.

“If there’s a mismatch between the speed of those two or three activities, we’re going to have to do something to slow things down so that we keep the grid reliable,” van Welie told reporters in an online briefing on the state of the region’s power grid.

“The more we constrain oil, the more complicated, the more tenuous it makes our operations,” he said. “We have resources that are retiring, we have state environmental regulations that are aggressively lowering the amount of emissions that can be produced by fossil generators, and we have the states moving forward aggressively to invest in behind-the-meter resources, including energy efficiency and new renewable resources.”

In January, the RTO released an Operational Fuel-Security Analysis that examined 23 fuel-mix scenarios and concluded that inadequate fuel supplies would cause power shortages under 19 of the scenarios by winter 2024-25. Those shortages would require emergency actions such as voluntary energy conservation and involuntary load shedding, or rolling blackouts. (See Report: Fuel Security Key Risk for New England Grid.)

Smoker of a Cold Snap

During two weeks of bitter cold surrounding New Year’s Day, New England generators burned through nearly 2 million barrels of oil, more than twice the amount used by the region’s power plants during all of 2016, van Welie said.

Gordon van Welie ISO-NE natural gas wind — | *ISO-NE*

Oil supplies at plants around New England declined rapidly during the cold spell as gas prices spiked and dual-fuel plants switched to oil, but the RTO avoided serious reliability issues thanks to LNG shipments. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)

Contributions from other types of generators were crucial during the cold snap, according to the RTO’s analysis.

“For instance, electricity produced by the Millstone nuclear station during the cold spell is equivalent to what could be produced by about 880,000 barrels of oil, and the power from the Mystic 8 and 9 units in Boston, which are fueled by LNG from the nearby Distrigas import facility, was the equivalent of more than 360,000 barrels of oil,” van Welie said.

High oil consumption means higher emissions. At the end of the cold snap, just one week into 2018, several oil-fired generators were already nearing their annual emissions limits, he said.

“The region can pay the bill for its fuel-security risks periodically, in spiking wintertime prices and potential energy shortages, or the region can pay the costs proactively and avoid reliability risks by investing in infrastructure, firm fuel contracts and other incentives,” van Welie said.

That new infrastructure could include further efficiency measures, transmission lines, renewable energy resources, storage facilities for liquid fossil fuels and gas pipeline infrastructure.

“Clearly, as one makes some of these infrastructure investments, you begin to lower the costs of the reliability services that the ISO seeks to procure,” van Welie said.

As oil resources retire — including those solely fueled by oil — the grid becomes more dependent on imported LNG or dual fueling, he said.

“I think the dual fueling becomes more constrained given the emissions constraints in the region,” van Welie said. The solution is “really a combination of electricity imports from neighboring regions and LNG as the balancing fuels as we put more and more renewables on the system, and that’s assuming we make no more investment in the gas infrastructure.”

Since 2000, the share of oil- and coal-fired generation in the region’s power production has fallen from 40% to less than 10%, while natural gas has risen from 15% to about 50%, he said.

Wind and CASPR

Solar has “exploded” in New England, largely because of state incentives, van Welie said, growing from 250 MW to 2,400 MW in just five years. Most resources are located in more than 130,000 small installations on homes or businesses.

And last year, wind power for the first time surpassed natural gas for the volume of generation seeking interconnection in the RTO’s queue. About 4,000 MW of that proposed wind would be located offshore of Massachusetts, with most of the remaining 4,500 MW onshore in Maine. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)

As the amount of wind and solar power continues to grow, in part driven by state policies, the RTO in January proposed a new two-stage capacity auction, Competitive Auctions with Sponsored Policy Resources (CASPR), to enable its Forward Capacity Market to accommodate state policy-sponsored, clean energy resources in the wholesale market, while maintaining a viable economic model for existing power plants. (See ISO-NE Defends CASPR Against Protests.)

CASPR, which the RTO proposes to implement on June 1, would “fully integrate demand response resources … into the competitive energy and reserves markets, where they can compete with conventional generators,” van Welie said. “ISO New England will be the first in the country to fully integrate DR into energy dispatch, building on its longstanding commitment to DR.”

The most effective way to achieve the states’ environmental objectives is to put an appropriately high price on carbon, van Welie said, because it would spur investment in cleaner resources.

“That could be the most efficient way of doing it through a wholesale market mechanism,” van Welie said. “It would allow us to avoid making this CASPR proposal that we recently filed at FERC. But we do understand that’s not the preferred choice of the states, and we respect that, and hence we have come up with this method for accommodating what they’re doing through above-market contracts.”

February 27, 2018

Sempra Joins ‘Three-Pronged’ Wildfire Front

By Jason Fordney

Sempra Energy on Tuesday became the third California-based energy company to promise a “three-pronged” effort to recover costs related to wildfires and push back on liability for having potentially caused some of the state’s deadly — and costly — fires.

During an earnings call, Sempra Energy CEO Debra Reed said that many factors are contributing to the worsening scope and spread of wildfires and that “it is irrational to place all of the burden strictly on utilities.” She said a hearing held in the Assembly on Monday on the wildfire issue was a favorable development. (See Wildfires Ignite Worries at CPUC, Legislature.)

“There is a focus now on how to resolve this inverse condemnation issue now legislatively,” she said, adding that the California Public Utilities Commission (CPUC) and Legislature are working more closely on the issue. “I think there is going to be some movement in that area.”

FERC Sempra Energy cost recovery SDG&E — SDG&E parent Sempra Energy released its fourth quarter and 2017 earnings on Tuesday | *Sempra Energy*

The “inverse condemnation” principle states that “the costs of a public improvement benefiting the community should be spread among those benefited rather than allocated to a single member of the community.” California utilities have cited the principle in their attempts to recover the cost for repairing infrastructure damaged by wildfires.

CPUC in late November denied $379 million in cost recovery to Sempra subsidiary San Diego Gas and Electric (SDG&E) for wildfires that occurred in 2007, despite the company’s use of the principle. (See Besieged CPUC De n ies SDG&E Wildfire Recovery.) The state’s other two investor-owned electric utilities, Pacific Gas and Electric and Edison International, have joined in requests for a rehearing of the CPUC decision.

“We will proceed expeditiously in the court” if CPUC denies rehearing, Reed said Tuesday. “I think that it is important to remember FERC approved full recovery for the same fires and same facts over four years ago.” In 2011, a portion of SDG&E’s costs associated with the settlement of 2007 wildfire-related damage claims was identified as allocable to SDG&E’s FERC jurisdiction assets, initially totaling $19.7 million, according to company statements.

Sempra began discussing legal action last fall after the decision CPUC decision on the 2007 fires affected third-quarter financial results. (See SDG&E’s Wil d fire Costs Undercut Sempra Profits.)

Financial Results

In the fourth quarter of last year, Sempra recorded a loss of $501 million ($0.51/ share), compared with earnings of $379 million in the fourth quarter of 2016. Excluding the impact of an $870-million expense in the fourth quarter related to last year’s passage of the federal Tax Cuts and Jobs Act, a CPUC decision on 2007 wildfire cost recovery, and other factors, adjusted earnings were $389 million, compared with $383 million during the same period a year earlier, Sempra sa i d.

“A portion of this income-tax expense relates to Sempra Energy’s plans to repatriate approximately $1.6 billion of undistributed foreign earnings over the next five years,” the company said.

The acquisition of Texas utility Oncor is another central issue for Sempra, and Reed noted the Public Utility Commission of Texas is due to vote on the deal as early as March 8. The U.S. Bankruptcy Court for the District of Delaware on Monday confirmed a reorganization plan for Oncor’s parent company, Energy Future Holdings, including the California company’s $9.45 billion acquisition of EFH and its 80% interest in Oncor (See Bankruptcy Court OKs Sempra-O ncor Deal.)

Sempra also reached a revised settlement regarding retirement of the San Onofre Nuclear Generating Station and resolved legal claims on the Aliso Canyon natural gas leak. Sempra subsidiary SoCal Gas has resumed injections at the gas storage facility, where limited withdrawals have contributed to gas supply concerns in Southern California.