Page 1154 – RTO Insider

January 9, 2020

PJM: BRA Unlikely in 2020

By Christen Smith and Rich Heidorn Jr.

VALLEY FORGE, Pa. — PJM officials said Wednesday that they won’t run a capacity auction until FERC approves the RTO’s compliance filing implementing the expansion of its minimum offer price rule (MOPR), making it unlikely the delayed 2019 auction will occur this year.

PJM must make a compliance filing by March 18 in response to FERC’s 2-1 ruling expanding the MOPR to all new state-subsidized resources.

“We do not plan to run a [Base Residual Auction] until we have an approval of that compliance filing. There’s so much at stake. … It is extremely risky for us to do that, and it’s a little bit too much risk for us to take on,” Adam Keech, vice president of market services, told the Market Implementation Committee during the first stakeholder meeting on MOPR since FERC’s Dec. 19 order. (See FERC Extends PJM MOPR to State Subsidies.)

PJM’s Pat Bruno indicated later that an auction before year-end was unlikely although it was “technically possible.”

Noting that FERC rejected most of PJM’s proposals, Keech also said the RTO is likely to file a request for rehearing or clarification of the order for its “procedural value.” Rehearing requests are due Jan. 21.

“We want to make sure we’re not marginalized in ongoing proceedings,” General Counsel Christopher O’Hara explained, highlighting the possibility that the order will be the subject of an federal appellate court proceeding.

PJM Base Residual Auction — PJM CEO Manu Asthana made his first public appearance Wednesday since joining the RTO. | © *RTO Insider*

“It’s going to be near impossible for the commission to accept the compliance filing without also granting at least clarification in part, and perhaps some of those clarifications cross over into rehearing,” O’Hara added. “I’m not talking major issues; I’m talking about some smaller issues.”

Wednesday’s meeting also marked the first public appearance by PJM’s new CEO, Manu Asthana, who began work last week. Asthana, who spoke briefly at the beginning of the MOPR discussion, said he and other board members want to incorporate stakeholder feedback in the compliance filing.

“We want to listen to … your perspective on the order: what it means for your business and what you want us to do about it,” he said.

Stakeholders: Resume BRA ‘ASAP’

The five-and-a-half-hour MOPR discussion also featured presentations by more than a dozen stakeholders who gave varying interpretations on the impact of the order and how PJM should respond.

Calpine — which filed the complaint that led to the commission’s June 2018 order finding the existing MOPR not just and reasonable — called for swift scheduling of the 2019 BRA. (See FERC Orders PJM Capacity Market Revamp.)

“There is nothing to debate. FERC issued its order, an order we have been waiting for over a year, and it’s time to proceed,” Calpine said. “Eighteen months have passed, and it is now PJM’s responsibility to hold the auction as soon as possible.”

The PJM Power Providers group agreed, saying the BRA should be resumed “ASAP.” The American Petroleum Institute, which represents both natural gas producers and large energy users, called for “a timely restart” of the BRA “and a clear signal of future regular auctions.”

But American Municipal Power, which owns and operates generation, transmission and distribution for municipal utilities in nine states in PJM and MISO, said the RTO should seek an extension of the 90-day compliance filing deadline.

AMP said the additional time would allow PJM to use a “transparent” process to craft a response that could minimize further litigation and uncertainty.

Exelon said PJM should set the 2022/23 BRA about 12 months after the compliance order to allow state regulators and legislators time to make rule changes required if they decide to exit the capacity market and develop fixed resource requirements (FRR) as an alternative method of resource adequacy.

Exelon’s Jason Barker said PJM that must “offer a meaningful opportunity for states to consider and pursue alternatives” to the RTO’s capacity procurement.

“FERC has provided the states with a binomial choice for shaping the capacity mix to achieve their environmental goals: participate in the PJM capacity market — which does not value environmental attributes — or direct their utilities to establish an FRR.”

Jeff Dennis, general counsel for Advanced Energy Economy, whose members include renewable generators and companies providing demand response and energy efficiency aggregation, said it’s likely PJM will need to postpone the 2020 auction as it did the 2019 BRA. A former FERC official, Dennis told an AEE webinar on the MOPR ruling Wednesday: “We are likely many, many months away from a capacity auction.”

Disagreement over RGGI

The speakers gave differing views on whether the commission’s definition of state subsidy would impact the resources of states participating in the Regional Greenhouse Gas Initiative.

Keech said PJM may seek FERC clarification on how RGGI and New Jersey’s Basic Generation Service (BGS) Electricity Supply Auction are impacted by the MOPR expansion.

In his dissent on the December order, Commissioner Richard Glick said the commission’s subsidy definition was likely to snare the BGS auction, in which electric distribution companies seek offers from resources to serve their load. That would require PJM and its Independent Market Monitor to “look behind the results of every BGS auction to determine which resources are receiving a benefit from this state process,” Glick said. “Even state processes that are open, fair, transparent and fuel-neutral may be treated as state subsidies, irrespective of the underlying state goals.”

“We’re not quite clear how those [programs] fit inside the … definition of a state subsidy,” Keech said. “Without more detail, it would seem like it would fall under state subsidy.”

Exelon said PJM’s compliance filing “should clarify that RGGI does not confer an actionable subsidy to any resources.”

Vistra Energy agreed, saying that although FERC’s subsidy definition is very broad, “we think it’s possible to implement it reasonably without implicating market-driven price outcomes” such as the RGGI carbon auctions.

The Advanced Energy Management Alliance said PJM should not consider DR as state-subsidized, saying “FERC precedent is to not include state peak shaving programs as subsidy.”

AMP made a similar pitch for the public power business model, citing what it called the “fallacy that tax-exempt financing constitutes a subsidy.” It called for a new stakeholder process to revise the RTO’s unit-specific exemption rules, saying PJM and the Monitor lack first-hand experience with the public power business model, “leading to incorrect comparisons of financing related costs for merchant projects and those available to not-for-profit public power organizations.”

The American Wind Energy Association and Solar Energy Industries Association said the unit-specific exemption process “must be flexible so all resource types … reflect their actual project costs, operations and projected revenues” and not be based solely on criteria used for setting the net cost of new entry for gas-fired generation.

Impact on Renewables, RECs

There also was discussion on FERC’s ruling to not differentiate voluntary renewable energy credits (RECs) from state-mandated RECs and disagreements over the impact the ruling will have on future renewable resources.

FERC said that although it saw no need to apply the MOPR to “voluntary, arm’s length bilateral transactions … it is not possible, at this time, to distinguish resources receiving privately funded voluntary RECs from state-funded or state-mandated RECs because resources typically do not know at the time of the auction qualification process how the REC will be eventually used.”

Vistra said voluntary RECs should not be considered subsidies. The company said it backs its renewable energy retail products with more RECs than needed to comply with state mandates. “MOPRing these purchases will mean that it is more expensive to offer these ‘green’ products to our customers, there will be fewer low carbon resources to source from than robust market dynamics alone would support, and there is an efficiency loss.”

Lightsource BP, a utility-scale solar developer with more than 1 GW of projects in the PJM interconnection queue, said voluntary RECs should not be considered state subsidies because they are a separate market from mandated RECs and trade at a fraction of solar compliance RECs.

It said vintage 2020 voluntary RECs are currently trading at 50 cents to $1/MWh, while solar RECs in New Jersey are worth about $227.50/MWh, $80/MWh in Maryland and $40/MWh in Pennsylvania. “As such, estimated project revenues from voluntary REC sales pale in comparison to estimated project revenues from state compliance RECs and should not be considered material,” Lightsource said, adding that PJM should mandate that capacity sellers use REC tracking systems to provide transparency to address FERC’s concerns.

“Forecasted PJM capacity market revenues are an integral component of PJM solar financeability, and a majority of the 1 GW in our PJM portfolio is at risk for being priced out of the capacity market auction,” Lightsource said.

But LS Power said the order would not impact its investments in intermittent resources because they don’t rely on the capacity market for significant revenues. It noted that wind and solar resources comprise only 1.2% of PJM’s capacity requirement. It said a 10-MW solar plant in New Jersey would see 80% of its revenues from RECs ($3 million), with energy market revenues contributing another $500,000 and capacity revenues adding only $250,000 (6.7%), assuming the market clears at $150/MW-day.

“Capacity is not the driving revenue stream for investment the way it is for other units needed for reliability that are dispatchable and flexible,” LS Power’s Marji Philips said. “PJM’s responsibility is making sure that plants that do rely on the competitive market that PJM also relies on for reliability have the appropriate price signals.”

Eliminate Capacity Market?

The Natural Resources Defense Council’s Sustainable FERC Project said the MOPR ruling “threatens to make PJM irrelevant” to states’ efforts to reduce carbon emissions.

It noted that 10 of PJM’s 13 states and D.C. have renewable portfolio standards, with D.C., Maryland and New Jersey having set or proposed 100% clean power goals, while three have laws supporting nuclear power.

“PJM should request rehearing and, if denied, seek appellate review of the MOPR order,” it said.

It also said PJM’s planning parameters should be changed to reflect the reliability value of uncleared capacity and that the RTO should ultimately retire the capacity market and develop an alternative resource adequacy structure.

PJM said it would post answers to stakeholders’ questions and hold a second stakeholder discussion on the ruling on Jan. 28. Questions can be submitted to RPM_Hotline@pjm.com.

January 9, 2020

ISO-NE Requests Delist Bid Flexibility for FCA 15

ISO-NE on Wednesday ask ed FERC to approve a limited Tariff waiver that would allow market participants to adjust or withdraw their retirement or permanent delist bids for Forward Capacity Auction 15, which are due March 13.

In seeking the flexibility for its participants, the RTO noted the potential for its Energy Security Improvements (ESI) market design to change after the submission deadline.

FCA 15 covers the capacity commitment period beginning June 1, 2024, when the grid operator now intends to implement ESI.

The New England Power Pool’s Markets Committee is meeting three days a month this winter to complete the ESI work before FERC’s April 15 deadline for a filing (EL18-182). (See FERC Extends ISO-NE Fuel Security Filing Deadline.)

ISO-NE FCA 15 — The 680-MW Pilgrim nuclear plant in Plymouth, Mass. | *NRC*

ISO-NE said that if FERC grants the waiver, retirement bids will remain due March 13 and that the waiver would apply in the event the RTO makes a non-clerical change to the ESI market rules, in which case a participant could either update or withdraw its delist bid.

“It is very possible” that the RTO will not have completed the market design and Tariff revisions for ESI by the existing capacity retirement deadline, it said in its request.

The Markets Committee will likely take an initial vote on ESI before March 13, but the design may evolve further before a final vote by the full NEPOOL Participants Committee is taken on or around April 2, 2020, the RTO said.

“Should this occur, the delist bids might not accurately reflect the impacts of the ESI market rules, in the form in which the rules are filed with the commission on April 15, 2020,” it said.

— Michael Kuser

January 9, 2020January 15, 2025

SPP Seams Steering Committee Briefs: Jan. 8, 2020

State regulators from the SPP and MISO footprints continue to discuss opportunities to contribute to the RTOs’ transmission planning analysis, Adam McKinnie, chief regulatory economist for the Missouri Public Service Commission, told the Seams Steering Committee on Tuesday.

McKinnie, who also serves as a contact between regulatory staff and the SPP Regional State Committee and Organization of MISO States’ Liaison Committee, said commissioners are interested in whether larger projects could resolve reliability issues along the seams.

Adam McKinnie, Missouri PSC | © RTO Insider

“They’re trying to figure out if there’s a role for states to play in encouraging wider solutions, rather than each RTO solving its own reliability problems,” McKinnie said.

SPP and MISO have taken three stabs at interregional projects but have failed to agree on a single solution.

The Liaison Committee, composed of regulators from both footprints, commissioned SPP’s Market Monitoring Unit and MISO’s Independent Market Monitor to analyze seams issues. The MMU produced a MISO, SPP Regulators Nibble Away at Seams Issues.)

The regulators have sought stakeholder feedback to a series of questions on the two studies. McKinnie assured the SSC that the responses are read. “That’s why we tried to provide ‘kitchen-sinky’ questions,” he said.

The Liaison Committee will hold a conference call Jan. 13 to discuss responses to the monitors’ reports. It will also meet Feb. 9 during the National Association of Regulatory Utility Commissioners’ Winter Policy Summit in D.C.

M2M Settlements Reach $68.1M in SPP’s Favor

SPP earned more than $870,000 in market-to-market (M2M) payments from MISO during November, cracking $68 million in favorable settlements since the process began in 2015.

Permanent flowgates were binding for 315 hours and more than $878,000 in SPP’s favor. Temporary flowgates were binding for 813 hours and more than $7,848 in MISO’s favor.

November market-to-market summary | SPP

Staff’s Will Ragsdale said two permanent flowgates along the Kansas-Missouri border — “our old friend,” the 161-kV Neosho-Riverton, and the 161-kV Moberly-Overton — accounted for more than $809,000 in M2M settlements to SPP. The Neosho-Riverton flowgate has racked up more than $30 million in settlements, four times the second-most constrained flowgate.

SPP has realized $68.1 million in M2M settlements since the two RTOs began the process of using the RTO with the most economic dispatch to address market flows. Staff are reviewing flowgates in western North Dakota to determine allocated property rights, or firm-flow entitlements, on M2M constraints and also comparing allocated M2M settlements with LMPs in market settlement areas.

Committee Reviews 2019, Preps for 2020

Committee members spent much of the meeting discussing the group’s organizational effectiveness, based on SPP’s annual stakeholder survey results. A suggestion to hold quarterly meetings because of a lack of voting items went nowhere.

Members also reviewed their 2019 accomplishments — including oversight of the MISO-SPP coordinated system plan improvements and study — and major pending issues. The latter includes joint studies with MISO and Associated Electric Cooperative Inc.; identifying the administrative processes that lead to inefficiencies between the SPP and MISO markets; and continued pursuit of coordinated projects to address historical M2M congestion between the RTOs.

Staff are working to set up SPP’s annual issues-review meeting with MISO, tentatively scheduled for March 10.

— Tom Kleckner

January 8, 2020

Bipartisan Bill Looks to End Va. Electric Monopolies

By Shawn McFarland

Dominion Energy might have finally met a “bill” it does not like.

Virginia delegates on Tuesday announced a bipartisan bill that would end the electric market monopoly in the state, allowing consumers to choose their electric provider and requiring distribution utilities to divest their generation. The legislation takes aim at Dominion, which serves two-thirds of the state’s consumers, and which the state Corporation Commission says has overcharged customers by $1.3 billion since base rates were frozen in 2015.

The bill was announced at a press conference by Del. Mark Keam (D–Vienna) and Del. Lee Ware (R–Powhatan) and endorsed by groups including the conservative R Street Institute and anti-poverty group Virginia Poverty Law Center. It’s the latest sign that Dominion will face tougher scrutiny from state lawmakers than it has in the past.

In December, Ware joined another Democrat in introducing a bill to reverse the General Assembly’s decision to freeze base rates for seven years, a change Dominion claimed it needed to ensure it could fund carbon emission reductions under the Obama administration’s Clean Power Plan. The CPP was cancelled by the Trump administration, which has proposed much less stringent regulations. (See EPA Finalizes CPP Replacement.)

Virginia Monopolies Bill — Del. Mark Keam | *Virginia Energy Reform Coalition*

“Over the past couple of decades, innovation and technological advancements have allowed consumers around the nation to choose when, where and how they obtain affordable and reliable energy. But in Virginia, we are stuck with a century-old business-as-usual model that benefits monopolies while suppressing competition and consumer choice. It’s time to reform the rules of the road,” said Keam. “We are done and are tired of ‘business-as-usual.’”

Under the current system, monopolies such as Dominion and Appalachian Power own and operate all segments of the state’s vertically integrated system, including generation, distribution and retail services. The bill announced Tuesday, which is set to be discussed in the 2020 General Assembly, would:

Establish a competitive market for electricity retailers to allow customers to shop on price or on environmental attributes (e.g., renewable energy);
Establish a nonprofit independent entity that has no financial stake in market outcomes to coordinate operation of the distribution system;
Remove existing interconnection and financing barriers to customer-owned energy resources; and
Add additional consumer protections and education to ensure smart energy choices.

Dominion and American Electric Power, parent of Appalachian Power, did not immediately respond to requests for comment.

“This legislation, which I trust will gain broad bi-partisan support, will chart a course toward engendering much-needed competition in the retail sales of vital electricity services,” said Ware. “This is a time of new opportunity.”

Keam and Ware claim Virginians have the seventh-highest electricity bills in the country. The utility has had its rates frozen since 2015 when the then Republican-led General Assembly removed state regulators’ ability to review base rates and set profit levels.

“It wasn’t until the rate freeze of 2015 that I came to the realization that this is really bad and really wrong. But only a handful of us said, ‘Why are we doing it this way?’ And the answers weren’t adequate,” Keam said. “So, from that point on until last year when we had that big fight over grid modernization, I think that’s awoke a lot of peoples’ understanding that we don’t have to take this.”

Dominion has long been one of the biggest political contributors in the state, having donated about $1.8 million in 2018-19 and $7.1 million since 2010, according to Virginia Public Access Project. In the past, most of the donations went to Republicans. In the most recent cycle, however, the utility donated slightly more ($949,000 to $870,000) to Democratic candidates.

But most Democratic legislative candidates agreed last year to reject funds from Dominion and made their opposition to the utility part of their campaigns. Nearly 50 of the 61 candidates that rejected Dominion money won their elections in November. With that, the Democrats took the majority in both the House and the Senate. The state’s governor also is a Democrat.

The bill proposed Tuesday is being backed by the Virginia Energy Re f orm Coalition, a group formed last year that includes both environmental organizations (Appalachian Voices, Clean Virginia and Piedmont Environmental Council) and right-leaning free market organizations (R Street Institute, Reason Foundation and Virginia Institute for Public Policy).

Devin Hartman, the director of energy and environmental policy at the R Street Institute, said the time is now for Virginia to embrace innovation.

“Virginia is shackled to a monopoly utility model that stifles innovation, increases costs and puts government in the difficult role of replacing competition,” he said. “It’s time for Virginia to liberate market forces, empower consumers and shift the role of government to facilitate competition. Competitive markets are the path to an innovative and consumer-friendly clean energy future. It’s time for Virginia to make the right choice.”

January 6, 2020October 21, 2025

Counterflow: When All Else Fails, Read the Order

By Steve Huntoon

By now we’ve all been told that FERC’s recent order on PJM’s minimum offer price rule is the death knell for renewables and a big hit to consumers.

This is the spin from renewable advocates who didn’t actually read the order before firing off press releases.[efn_note]The order was posted at 5:51 p.m. ET on Dec. 19, 2019, after press releases were issued. Other groups also didn’t read the order before firing, but their shots in the dark weren’t so far off the mark.[/efn_note]

Let me explain four elements of the order that are positive for renewables, and then discuss the consumer rate hike that isn’t.

The Death Knell for Renewables that isn’t

Existing Renewables are Grandfathered, Fossil and Nuclear Aren’t

This is a big preference for renewables. It also means that to the extent uneconomic subsidized fossil and nuclear units retire, energy prices for renewables increase.

Renewables Depend Much less on Capacity Revenues for Project Viability

Renewables’ nameplate capacity is heavily discounted for Reliability Pricing Model purposes because of their intermittency. As a consequence, renewable projects are much less dependent on RPM revenue for project viability.

By the way, those complaining that renewables will lose project-critical RPM revenues are some of the same wanting to get rid of RPM altogether. Which is it?

The Unit-specific Exemption Favors Renewables

There is an exemption for projects that can show financial viability even without a state subsidy. And it would seem many renewable projects will be able to satisfy the test because of the generic nature of their subsidies.

State subsidies for fossil and nuclear units are tailored to providing just enough money to keep specific units around. So by definition — or at least by representations to state legislators — they have to have the subsidies to be financially viable, which in turn would mean no unit-specific exemption for them.

Federal Subsidies are Excluded

This is a big preference for renewables because their federal subsidies per megawatt-hour are enormous, averaging $21.50, with fossil and nuclear subsidies less than 1/10 of that. Here’s a chart with the data:[efn_note]https://live-energy-institute.pantheonsite.io/sites/default/files/UTAustin_FCe_Subsidies_2017_June.pdf, page 23, Table 7, FY 2019 (“HC” stands for hydrocarbons oil and natural gas). By the way, historical subsidies that no longer exist, and aggregate dollar amounts of subsidies, are irrelevant to relative subsidy value among resources. What is relevant is amount of subsidy per unit of generation.[/efn_note]

Yet, renewable advocates complained about federal subsidies for fossil being excluded. OMG.

The Consumer Rate Hike that isn’t

At some point, we’ll have some rigorous modeling of the consumer impact. There are a lot of moving parts, including how significant the unit-specific exemption turns out to be.

One thing we know now is that the consumer rate hike claimed by some advocates is a fantasy. They rely on a study that claimed an increase in RPM consumer costs of $5.7 billion compared to the last RPM auction.[efn_note]https://www.sierraclub.org/press-releases/2019/12/ferc-costs-consumers-billions-hobbles-clean-energy-economy-help-coal-and; https://www.eenews.net/stories/1061856193; https://www.vox.com/energy-and-environment/2019/12/23/21031112/trump-coal-ferc-energy-subsidy-mopr. The study relied upon is here: https://gridprogress.files.wordpress.com/2019/08/consumer-impacts-of-ferc-interference-with-state-policies-an-analysis-of-the-pjm-region.pdf.[/efn_note] This estimate was based on 24,000 MW being subject to the MOPR.

There are fatal flaws in that study. First is that at least 16,416 MW of the 24,000 MW didn’t clear in the last RPM auction.[efn_note]The 16,416 MW is composed of 14,300 MW of future renewable resources and 2,116 MW of Ohio nuclear units that did not clear in the last RPM auction. https://www.prnewswire.com/news-releases/firstenergy-solutions-comments-on-results-of-pjm-capacity-auction-300654549.html.[/efn_note] So the study is estimating a price increase by subtracting capacity resources that weren’t there to subtract in the first place.

Now let’s look at what’s left after subtracting the nonexistent 16,416 MW from the 24,000 MW. The roughly 7,600 MW that’s left is made up of three nuclear plants (Hope Creek and Salem in New Jersey, and Quad Cities in Illinois) and one coal plant (Ohio Valley Electric Corp.). The FERC order requires that offer prices be adjusted to the net avoidable cost rate, which is the gross going-forward cost net of estimated energy, capacity and ancillary services market revenues. Independent Market Monitor data show that none of the nuclear plants in question needs revenues in excess of estimated total energy and capacity revenue in order to remain financially viable.[efn_note]http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2019/2019q3-som-pjm-sec7.pdf, Tables 7-20 and 7-21 (The MMU didn’t include ancillary services, which would add to revenue.)[/efn_note] The necessary implication of this is that their minimum offer price will be below the locational deliverability area clearing price for the respective units.

As for the coal plant, generic PJM data show a gross going-forward cost of $171/MW-day and very conservative energy and ancillary services revenue of $45/MW-day.[efn_note]Initial Submission of PJM Interconnection, LLC, Docket No. EL16-49-000, https://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=15059002, pdf pages 118 and 120.[/efn_note] Netting the $45/MW-day from the $171/MW-day gives a MOPR replacement rate of $126/MW-day, which is below the $140/MW-day RTO clearing price in the last auction. Thus, the coal plant clears without affecting the RTO clearing price.

Although not part of the study reviewed above, let me add a note on Commissioner Richard Glick’s estimate that 25% of demand resources that cleared in the last auction won’t clear in the next one allegedly because a curtailment service provider (effectively an aggregator) will need to know its specific end-use customers three years in advance. This does not consider that the FERC order exempted all demand response resources that cleared in a prior auction, i.e., all the DR resources that Glick says are subject to the MOPR. Moreover, CSPs already live with some uncertainty about their ultimate end-use customers; no state subsidy for DR has been identified; and DR resources could alleviate uncertainty for CSPs by certifying to current and future nonreceipt of state subsidies (which, as noted, don’t even seem to exist).

To sum up: No effect on the last RPM auction results.

Yes, you read that right. No increase in RPM consumer costs relative to the last auction.

Speaking of reading, might I recommend the order?

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

January 6, 2020

Pioneer Tx OK’d to Recover $10M in Development Costs

By Amanda Durish Cook

Pioneer Transmission can recover about $10 million in precommercial operation costs used to develop a high-voltage transmission line in Indiana, FERC decided last week.

The joint venture of Duke Energy and American Electric Power incurred the costs March 2009 through Dec. 31, 2019, while planning and constructing the $347 million, 765-kV Greentown-to-Reynolds transmission line between Kokomo and Reynolds, Ind. FERC approved Pioneer’s October filing to include the asset in its formula rate on Dec. 31 (ER20-159).

However, the commission also told the transmission company it must update its capital structure from the hypothetical 50% debt and 50% equity to the 2018 year-end actual of approximately 51.1% debt and 48.9% equity.

The 70-mile Greentown-to-Reynolds project is the first segment of the $1 billion, 290-mile Greentown-to-Rockport line that has been in the works for more than a decade. The completed line is expected to traverse MISO into PJM. Pioneer began construction on the segment in 2013 and finished work in June 2018; the segment is one of the 17 multi-value projects MISO approved in 2011.

Pioneer Transmission — The Greentown-to-Reynolds line | *Duke Energy*

In a related order issued the same day, FERC also denied Pioneer’s request to rehear its first request to amortize and recover the precommercial operation costs of the Greentown-to-Reynolds line (ER18-2119).

Pioneer first filed to recover precommercial operation costs in July 2018, but the commission rejected the filing without prejudice a year later, finding that the company included a 150-basis-point return on equity adder for new transmission in its carrying charges. FERC had previously said in 2009 that Pioneer could not receive the adder unless the project was approved by both MISO and PJM. Pioneer has not yet obtained PJM approval for the project. (See FERC Lowers ROE for Segmented Pioneer Tx Project.)

Pioneer said FERC should revisit the decision because the commission did not act within the 60-day period prescribed by the Federal Power Act, thus making the filing legal on Sept. 30, 2018.

But FERC said Pioneer’s regulatory asset filing was not properly filed electronically and therefore was not subject to a statutory action date.

“If we were to vacate the commission’s rejection of Pioneer’s filing in this docket as Pioneer requests, it would be permitted to accrue an unauthorized 150-basis-point ROE adder to its regulatory asset carrying charge and thus profit through its own failure to comply with the commission’s filing regulations,” FERC explained, pointing out that Pioneer was able to submit its October filing correctly.

January 6, 2020

Changes at the Top for SPP in 2020

By Tom Kleckner

“Evolutionary, not revolutionary,” Southwest Power Pool executives like to say about their RTO. It’s written into SPP’s corporate culture, the idea being that it takes time “to do the right thing, for the right reason, in the right way every time.”

The RTO’s emphasis on continuity will be tested in 2020, however. By midyear, SPP will be without five of the key figures who have helped expand the grid operator’s footprint into 17 states and implement a day-ahead market. Former Board of Directors Chair Jim Eckelberger and Directors Harry Skilton and Phyllis Bernard left the board at year-end after having served together since 2003. COO Carl Monroe will follow them out the door after January.

Come April, CEO Nick Brown, who joined the RTO 35 years ago as employee No. 7, will retire. SPP, having identified both internal and external candidates, says it is on track to announce his replacement during January’s board meeting in Santa Fe, N.M. (See SPP’s Brown to Retire as CEO in 2020.)

Southwest Power Pool Board Chair Larry Altenbaumer — SPP Board Chair Larry Altenbaumer | © *RTO Insider*

Larry Altenbaumer replaced Eckelberger in January 2019, seeking to place his own stamp on the RTO by shortening board meetings and focusing them on strategic discussions with members and the Regional State Committee. In addition to taking over the chairmanship of the Strategic Planning Committee, he also headed the Affordability and Value Task Force, which identified “meaningful opportunities to enhance other aspects of performance.” (See SPP Value Group Finds No ‘Silver Bullets’.)

Dennis Florom, manager of energy and environmental operations for Lincoln Electric System, said that as SPP grows in size and membership, “it gets more difficult to keep things member-driven,” referencing the RTO’s preference to serve as advisers to members.

“This is what sets SPP apart, and SPP prides itself on that. The new CEO will need to work with the board to make sure that SPP maintains its identity and that members continue to set the direction as forks in the road present themselves,” Florom said.

SPP’s expansion into the Rockies and beyond has already reached the crossroads.

In early December, the RTO became the reliability coordinator for 15 Western Interconnection utilities, representing about 12% of the region’s load. (See Westward Ho: SPP Now a Western RC Provider.) However, shortly thereafter, SPP’s ambitions to run an energy market in the Western Interconnection took a hit with news that Colorado’s largest utility (Xcel Energy) and three others chose CAISO’s Western Energy Imbalance Market over its own competing market offerings. (See EIM Lands Xcel, 3 Other Colo. Utilities.)

The RTO is still plugging ahead with its Western Energy Imbalance Service, which is scheduled to go live in early 2021. Two additional utilities, Municipal Energy Agency of Nebraska and Wyoming Municipal Power Agency, have announced they will join the five that signed contracts in September to fund WEIS’s development: Basin Electric Power Cooperative; Tri-State Generation and Transmission Association, and three Western Area Power Administration entities, Colorado River Storage Project; Rocky Mountain Region and Upper Great Plains. (See SPP Board OKs $9.5M to Build Western EIS Market.)

“Discussions continue with other interested parties, but no additional contracts have been signed at this point,” SPP spokesman Derek Wingfield said.

CAISO’s EIM, which currently has nine members, is expected to grow to 23 by the end of 2022.

Competing for Load

In the meantime, there’s plenty for the grid operator and its members to chew on. The explosive growth of renewable energy shows no signs of easing. Wind farms and, more recently, solar installations and energy storage, continue to add more energy than SPP — with a reserve margin of around 25% — knows what to do with.

SPP set a new wind peak record of 17,861 MW on Dec. 11, breaking a mark set two months earlier by 266 MW. In the early-morning hours of Oct. 9, the RTO produced 73.67% of its energy from wind, hydro and other non-fossil resources, fulfilling predictions a year before that it would reach the 70% threshold.

Dennis Florom, Lincoln Electric, at a Southwest Power Pool stakeholder meeting — Dennis Florom, Lincoln Electric | © *RTO Insider*

Florom said that a peek at the generation interconnection queue “shows a level of renewables that SPP load can’t handle.” The RTO had more than 22 GW of installed wind capacity as of October, with more than that in the queue.

Florom suggested storage and new transmission could “present opportunities for addressing more renewables.”

“Tariff changes and working with other entities outside of SPP to export these renewables are ways that SPP can address this challenge in ways that might benefit everyone,” Florom said.

But exporting energy could require additional transmission construction, which comes with a cost. Altenbaumer is keenly aware that members are still digesting the $10 billion in transmission construction and upgrades over the previous decade.

“The big concern [stakeholders] have is what happens with the next wave of transmission projects and making sure they pass a very tight metric to provide value,” he said in November.

Some of the answers may lie in the implementation of the Holistic Integrated Tariff Team’s recommendations. (See SPP Board Approves HITT’s Recommendations.) State regulatory staff are working on some of the key recommendations, including creating larger transmission pricing zones and sub-zones; evaluating the byway facility cost allocation review process; and evaluating cost allocation and rates for storage devices classified as transmission assets.

Other stakeholder groups are working on an uncertainty market product, improvements to the day-ahead market — including a multiday, longer-term market product — and establishing uniform local planning criteria within the Tariff’s Schedule 9 pricing zones.

SPP’s staff take a deeper view into the future. During a Strategic Planning Committee meeting in November, Senior Engineering Vice President Lanny Nickell said the RTO and its stakeholders should be “thinking about” competition between RTOs and keeping its own load while competing for other loads.

“How do we compete, as a region, for loads that love the renewable resources and [their] low prices?” he asked. “They’re looking for opportunities to add warehouses and data centers. How do we compete for those?”

“Given concerns with costs, we can’t afford to lose much load as we calculate administrative costs and move forward in a world that is changing rapidly,” said Bruce Rew, senior vice president of operations. “We can’t afford to lose megawatt one.”

Change is coming. Whether it’s evolutionary or revolutionary, a new cast of characters at the top will be the ones to address it.

January 6, 2020

GreenHat Claims Fund Opens After FERC OKs Settlement

PJM last week sent members directions on how to file claims against the $5 million fund established in the GreenHat Energy settlement just days after FERC accepted the terms of the agreement.

In October, PJM filed its plan with the commission to pay two trading firms $12.5 million to settle claims of economic harm that resulted from the RTO’s decision to not liquidate GreenHat’s entire 890 million MWh portfolio of financial transmission rights during the 2018/19 planning period (ER18-2068).

After the company defaulted in June 2018, PJM reran only the July FTR auction — a decision the RTO says kept costs to members down and avoided a cascade of market violations that would increase uncertainty for years to come. (See PJM to Pay $12.5 million to Settle GreenHat Dispute.)

GreenHat’s significant growth in exposure and MTA loss | *PJM*

As part of the settlement, members agreed to fund a separate account that would pay out additional claims if PJM’s analysis verified those market participants also suffered economic harm. If PJM discovers instead that a claimant benefited from prior actions, it will owe a fee equal to 50% of the amount of the benefit. The RTO said in October that it doesn’t expect additional claims, based on the limited protest filings it received during the proceeding.

In its email to members Thursday, PJM directed potential claimants to submit an email to FTRPayeeFund@pjm.com with “Payee Fund Claim” in the subject with the name of the market participant in the body of the email on or before Feb. 1. Claimants should not include a dollar amount for which the market participant was harmed.

PJM said it will notify claimants by Feb. 10 of the harm or benefit for the market participant and what amount will be credited or charged, respectively, to its monthly billing statement following the notification.

— Christen Smith

January 6, 2020

ISO-NE Energy Security Plan Looms Large in 2020

By Michael Kuser

ISO-NE kicks off 2020 with a key deadline looming to file a long-term fuel security mechanism with FERC — a project two years in the making.

The New England Power Pool Markets Committee worked double-time through the fall to complete the Energy Security Improvements (ESI) program to address winter fuel security concerns. This year, it will meet three days a month to complete the work before FERC’s revised deadline of April 15 (EL18-182). (See FERC Extends ISO-NE Fuel Security Filing Deadline.)

Stakeholders are discussing LNG supplies, market mitigation and a second demand curve to ensure the RTO can meet forecast load throughout the next operating day.

The Participants Committee likely will vote on the new market construct at its April 2 meeting, and stakeholders will learn of any schedule additions early this month.

Based on regular surveys on generator fuel supplies for this winter, the RTO estimates that more than 4,500 MW of gas-fired generating capacity could be unable to get fuel when needed. (See “RTO Cautions on Availability of Fuel in Cold Snaps,” ISO-NE Projects Adequate Resources for Winter.)

This is the first winter season since the 680-MW Pilgrim nuclear plant retired in May. The RTO said the plant’s capacity is being replaced by several new resources, including three dual-fuel plants, as well as solar and wind resources.

Stakeholder Proposals

What’s taking so long to complete the plan? To begin with, stakeholders have varying opinions and have offered several proposals.

Calpine proposed a Forward Enhanced Reserves Market that would procure fuel-secure winter energy three years in advance.

The Massachusetts attorney general’s office, which recommended a call option that would be sold in a simple auction of sealed bids with a uniform clearing price, withdrew its proposal in August. In September, it said it was keeping its options open on several amendments to the ESI proposal, depending on the flow of analyses and discussion in the lead-up to April’s filing.

Eversource Energy presented an amendment to address the company’s concern that the RTO’s Inventoried Energy Program would overlap with ESI for winter 2024/25.

The Connecticut Public Utilities Regulatory Authority and Department of Energy and Environmental Protection jointly presented an amendment to the Tariff language concerning quarterly certification of the competitiveness of the energy call option offers in the day-ahead market.

FirstLight Power Resources proposed that the option strike price — intended to estimate the marginal price of energy to meet next day’s forecasted load plus operating reserves — needs to vary by hour, just as marginal energy prices do.

Market Concerns

Even the U.S. Senate got in on the act in November, as seven senators from New England urged ISO-NE to “return to the table with stakeholders” and more closely align its fuel security initiative with state policies seeking to speed the transition to renewable energy resources. (See Senators Ask ISO-NE to Heed States on Clean Energy.)

In a letter to the RTO, the senators criticized it for “pursuing a patchwork of market reforms aimed at preserving the status quo of a fossil fuel-centered resource mix” and having “charted its own path forward and pursued unpopular initiatives” such as Competitive Auctions with Sponsored Policy Resources (CASPR) and the Inventoried Energy Program.

“CASPR was really just a mechanism we invented and work around to allow such resources to enter the market without crashing the price in the primary auction capacity market,” ISO-NE CEO Gordon van Welie said at a conference in November. (See Overheard at NECBC 2019 Energy Conference.) “When we set out to change anything in our markets, it’s at least a three-year market design, stakeholder journey … with anything substantive likely to be litigated.”

Energy market values vary with fuel prices, while capacity market values vary with changes in supply ($ billions). | *ISO-NE*

Former FERC Chair Joseph T. Kelliher, now executive vice president for federal regulatory affairs at NextEra Energy, said at the same event that “to the extent there’s a crisis in the industry, it’s a crisis of low energy prices.”

At another conference, Massachusetts Department of Public Utilities Chair Matthew Nelson said, “I don’t think markets are broken; it’s just that the world has changed around the markets. Regardless of our personal or political positions, the reality in the market is one of increasing demand for clean resources.”

Nelson likened today’s market to a three-legged stool balancing clean energy, cost and reliability.

“Reliability today is king in the electric market, but the relationship between reliability and clean energy is not binary,” he said. “The narrative that a clean future can only come at the expense of reliability is false. It’s not a zero-sum game.”

Speaking at the Northeast Energy and Commerce Association’s Power Markets Conference in November, FERC Commissioner Richard Glick said, “I never realized until I got to FERC how complicated some of these markets have grown … and we see a lot of proposals to tinker with the markets, particularly the capacity markets.” (See Overheard at NECA 2019 Power Markets Conference.)

Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides in December said that she is focused on bringing new renewable resources into the market and electrifying the transportation and building sectors to take advantage of new hydro, wind and solar resources as they come online. (See Overheard at the 1st New England Energy Summit.)

“We really feel you need to do those two pieces at the same time. You don’t just clean up your power and then do electrification next,” Theoharides said.

Big, Slow Clean Energy Projects

Massachusetts has been facing delays in some of its larger state-sponsored renewable energy projects, as has Avangrid, which is partnered on two of the projects.

Avangrid said in November that it expects “in the not too distant future” to get the final permits on its New England Clean Energy Connect (NECEC) project to bring 1,200 MW of Canadian hydropower to Massachusetts. The company expects to begin construction in the second quarter this year and to be operational by 2022.

NECEC has been plagued by delays, controversy and opposition since it received the state contract following the failure of Northern Pass, a competing project by Eversource, to win regulatory approval in New Hampshire.

Avangrid’s offshore wind joint venture, Vineyard Wind, also saw trouble last year, as the U.S. Bureau of Ocean Energy Management in August delayed issuing a final permit in order to expand environmental impacts analysis for all such offshore projects. (See Renewable Backers Decry Vineyard Wind Delay.)

“All of the developers have agreed to 1 nautical mile of turbine spacing, so we hope the fishermen can do their fishing, and we expect a decision by the secretary of the interior by early January so we can start construction,” Avangrid CEO James P. Torgerson said.

ISO-NE’s activities now center on the grid’s transition to renewable resources, a topic to which the grid operator devoted a conference in May. (See ‘Grid Transformation Day’ Highlights ISO-NE Challenges.)

“It’s a much different grid from 10 years ago,” said Anne George, vice president for external affairs and corporate communications at ISO-NE, speaking at a public forum in December.

“The amount of wind in our interconnection queue is the greatest we’ve ever had,” she said, citing 13,720 MW, or 65% of the queue total of 21,138 MW. “And over the next 10 years, we’re going to see a lot more activity with battery storage.”

FERC in December conditionally accepted ISO-NE’s Order 841 compliance filing (ER19-470), requiring additional changes to how the RTO dealt with the application of transmission charges to storage resources and rejecting its approach for handling the state of charge and duration of those resources in day-ahead markets. (See Storage Plans Clear FERC with Conditions.) The RTO has requested a rehearing on the latter finding, contending that the commission’s recommended approach is “inferior” to its own proposal and could “jeopardize critical ISO-NE projects.”

The RTO’s next compliance filing is due Feb. 10.

Competitive Transmission

ISO-NE in December announced its first-ever competitive transmission solicitation to address peak load condition overloads in the Boston area and system restoration concerns with the underground cable system in the area.

The RFP seeks to address reliability concerns associated with the upcoming retirement of the Mystic Generating Station in Everett, Mass. (See ISO-NE Issues First Competitive Tx RFP.) The RTO will review all proposals in a two-step process before selecting the preferred solution, with a March 4 deadline for submissions.

ISO-NE Energy Security — Potential New England 2050 load profiles by end use | *EPRI*

FERC earlier in December approved Tariff revisions refining ISO-NE’s rules for conducting competitive transmission solicitations in compliance with Order 1000, a process being tried for the first time for solutions to non-time-sensitive needs identified in the RTO’s 2028 Boston Needs Assessment Update and Needs Assessment Addendum (ER20-92). (See FERC OKs ISO-NE RFP Rules.)

But the commission in October instituted Federal Power Act Section 206 proceedings, concerned that ISO-NE may be implementing the immediate-need reliability exemption in a manner “inconsistent with what the commission directed, and therefore may be unjust and unreasonable, unduly preferential and discriminatory” (EL19-90).

The RTO on Dec. 27 filed its response to the proceeding, concluding that “the exception is working as intended” and that no changes are necessary.

However, the RTO promised to conduct a “lessons learned” process following the completion of the Boston RFP to determine if improvements can be made.

January 5, 2020

FERC OKs $450,000 Avangrid Penalty

By Holden Mann

FERC last week accepted a $450,000 settlement between the Northeast Power Coordinating Council and three Avangrid utilities for violations of NERC transmission operations (TOP) standards. The commission indicated in a notice last week that it would not review the penalty (NP20-4).

According to a N otice of P enalty filed Nov. 26, the violations involving New York State Electric and Gas and Rochester Gas & Electric took place Nov. 17-28, 2017, while the Central Maine Power violation occurred Jan. 11, 2019. Both situations posed a moderate risk to the reliability of the bulk power system, though neither is known to have caused actual harm.

In the first violation, a server failed, affecting a transmission network analysis (TNA) tool used by both NYSEG and RG&E for several monitoring and assessment applications. A backup server also failed, leaving the TNA tool inoperative. As a result, both utilities were unable to perform real-time assessments every 30 minutes as required by the TOP-001-3 standard.

Avangrid Penalty — Avangrid’s New York and New England utilities serve 3.2 million natural gas and electricity customers. | *Avangrid*

Initially both utilities were unaware of the TNA failure and loss of monitoring and assessment capabilities, but at 1 a.m. — six hours after the incident began — the RG&E system operator discovered the breakdown and notified his counterpart at NYSEG. Neither operator notified reliability coordinator NYISO, which could have performed a real-time assessment. The server failure was not corrected until nearly four hours later, when monitoring and assessment capabilities returned. NYISO was not notified for more than 14 hours after the utilities became aware of the failure.

“The RC would not necessarily be aware that it may have to take support actions to address the lack of NYSEG/RG&E monitoring and assessment capabilities,” NERC said in its filing. “The risk posed is that if a system event occurred during this time frame, neither RG&E, NYSEG nor NYISO would have had the necessary situational awareness to respond.”

CMP’s violation of TOP-001-4 was similar, involving an accidental interruption of connectivity that led to the failure of a state estimator and a real-time contingency analysis tool. The outage lasted more than an hour, during which time CMP did not notify ISO-NE of the loss or request the RC perform a real-time assessment on its behalf. ISO-NE was informed of the outage after connectivity had returned and the tools were functional again.

In both cases, NPCC faulted the utilities for “lack of effective management oversight, including training,” with NYSEG and RG&E also criticized for lack of controls that would have detected the failure of monitoring and assessment capabilities. NPCC said the penalty was increased by an unspecified amount because CMP was already aware of the earlier incidents at the time of the January failure and hence should have known the importance of ensuring that the RC was notified and real-time assessments continued.

NPCC credited Avangrid for being cooperative throughout the enforcement process and accepting responsibility for the violations. The regional entity noted that the risk to the grid was moderate. NYSEG, RG&E and CMP have also implemented several mitigating measures, including hardware and software changes to detect faults with the reporting system, additional system operators, and new methodologies for training and staffing.

As a result, NERC’s Board of Trustees Compliance Committee approved the penalty as “appropriate for the violations and circumstances at issue.”