Page 1452 – RTO Insider

November 14, 2017November 11, 2023

Cooperation, DOE NOPR, State RFPs the Topics at NECBC Meeting

By Michael Kuser

BOSTON — Atlantic Canada, New York and New England are one region geographically, and the jurisdictions will be drawn into ever closer cooperation on energy.

That was the consensus among a dozen or so speakers at the 25th Annual Energy Trade & Technology Conference hosted by the New England-Canada Business Council on Nov. 8-9. Speakers also discussed proposed price supports for coal and nuclear generation and how FERC is likely to treat New England states’ contracting for renewables.

Battery for New England

Hydro-Québec CEO Eric Martel said that his company last year exported more than 15 TWh of electricity into New England, about 12% of what the region is consuming now. The company has partnered on six different projects being bid into Massachusetts’ recent clean energy procurement. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)

“Our large reservoirs have a combined annual energy storage of 176 TWh,” Martel said. “Today we are producing for the Canadian people 170 TWh/year [and] we are exporting about 30 TWh, which makes our production today at 200 TWh. But today our limit [on exports] is the number of transmission lines.”

Hydro-Québec began developing non-hydro renewable generation in the early 2000s and has since added 3,500 MW of wind capacity in Québec, Martel said.

“We firm up our domestic wind generation using our hydropower resources, so it’s very important that our source for firming is a renewable resource also,” he said. “We’ve been planning for this energy transition that is taking place, but what needs to happen now is to build those transmission lines. At peak periods, hydropower can be adjusted almost in real time, so Hydro-Québec can be the battery for northeastern America.”

NB Power CEO Gaëtan Thomas suggested how to connect the region to that huge battery.

“The only way to do that is more transmission,” Thomas said. “Transmission is king; transmission is going to solve these issues. Our vision should be to tie the whole region together and get to net zero [emissions]. That’s the only way we’re going to avoid the hits [caused by climate change] on the Eastern Seaboard. We’re all connected to it; we have that in common.”

DOE NOPR DOA?

Many speakers agreed that the U.S. Department of Energy’s recent Notice of Proposed Rulemaking in support of coal-fired and nuclear baseload generation wouldn’t amount to much, if anything.

But Concentric Energy Advisors CEO John Reed cautioned about being too optimistic.

“If we have one lesson from this administration, if you look at immigration or health care, the answer is, if at first you don’t succeed, tweet, tweet again,” Reed said. “If this doesn’t go somewhere, and if you look at the initiatives that have occurred in Ohio, Illinois and New York to support baseload generation, what is going to come down as the next mandate, the next executive order on these issues? Because I don’t think the administration’s concerns in terms of supporting coal and nuclear and other baseload generation are going to go away.”

“What I would expect — and PJM is already looking into it — is how to price things perhaps differently,” said Avangrid CEO James Torgerson. “And I think the other organized markets will probably be told to do the same thing. I think each RTO and ISO is going to be looking at it from their perspective, and [if there is] an issue in their area that needs to be dealt with. FERC will probably push it back to the different regions to get it resolved on a regional basis, because you can’t just say it’s a national or international problem at this point; it’s in certain pockets.”

Michael Twomey, vice president for external affairs at Entergy, defended nuclear energy’s role as an emissions-free resource. Nuclear power’s contribution to New England’s energy needs has remained generally unchanged because the retirement of Vermont Yankee was offset by upgrades and increased capacity from other units, he said.

“Oil has effectively disappeared from the landscape, coal is reduced significantly, and hydro and renewables honestly haven’t moved that much,” Twomey said. “We’ve seen tremendous gains in carbon emissions reductions in New England over the last 15 years, but that’s mainly been attributable to the substitution of natural gas for oil and coal. Well, the oil and coal is going to be gone — soon — and there’s not going to be any more low-hanging fruit to achieve carbon reductions, so what we’re going to see is probably an increase in carbon emissions from where we are now, going forward, as you see new retirements.”

An Accommodating FERC?

FERC is entering a much more “state-centric” cycle, according to Rob Minter, vice president for government and regulatory affairs at ENGIE.

“Confidence in the markets for maintaining things like fuel diversity to keep nuclear plants alive, to integrate renewables, to achieve public policy goals like carbon reduction does not fit with the market structure that we now have,” Minter said. “Everyone’s trying to build the type of plants they want for their own objectives, for their own fuel reliability, for economic development, to save stranded assets that are uneconomic and underwater but make sense, like a nuclear plant you need to continue to have low carbon. These are not compatible with the current wholesale market that was created in the 1992 Energy Policy Act.”

“You start wondering how much of this [NOPR] is about reliability and fuel diversity versus some of the generators who have coal and nuclear plants aren’t really making as much as they did in the past,” Torgerson said. “So those are things being debated right now.” He predicted FERC will set a technical conference so industry participants can examine the issue more thoroughly.

To implement different state public policies on clean energy requires out-of-market actions that are fundamentally incompatible with the wholesale market design, Minter said.

“You can find a way to price those attributes into the markets, but my god, you end up putting dozens of pricing mechanisms and algorithms into an already complicated market,” Minter said.

He said although he would prefer fully competitive markets, they have “very little chance of success.”

“I would like for it to work; I would like to see fully competitive wholesale markets,” he said. “But regulators are not willing to accept the risk of very high energy prices that happen during periods of scarcity.”

Leo Desjardins, CEO of Conservation Resource Solutions, said the new, fully staffed commission has arrived at an inflection point for markets.

“Massachusetts probably gets its way on Canadian imports [and] FERC figures out how to accommodate regional and state carbon pricing,” Minter said. “And I think you’ll see that [the] large renewable procurements that states want, that end up being out-of-market, get accommodated. Only for so long can a commission like FERC fend off states. If the number of states [asserting their public policy] grows, and as the frustration level grows, they eventually have to cave in and accommodate.”

November 14, 2017

PJM Planning and Transmission Expansion Advisory Committee Briefs: Nov. 9, 2017

VALLEY FORGE, Pa. — PJM’s Asanga Perera presented stakeholders at last week’s Planning Committee meeting with a problem statement and issue charge to address issues the RTO sees with its current process for evaluating market efficiency projects.

pjm market efficiency projects planning committee — Perera | © *RTO Insider*

“We have conducted two cycles to date since FERC Order 1000 was established, and during these two cycles, we recognized various challenges that we think are important to address going forward,” he said.

One of the issues, Perera explained, is that PJM’s benefit-to-cost calculations beyond 10 years are extrapolations, not more accurate simulations.

“We have discovered, in certain instances, we may end up either overstating benefits or understanding benefits, especially on a longer horizon,” he said.

PJM also must address modeling issues, timing of the proposal-window process, interregional analysis and project re-evaluation, Perera said.

Sharon Segner of LS Power applauded the focus on the process but asked if it could go further.

“This is a great discussion in terms of some of the challenges that the market efficiency window is facing,” Segner said. “Is there anything missing?”

PJM staff resisted suggestions to include a review of cost calculations, saying that’s being handled elsewhere.

Segner also warned against making any retroactive changes.

“It’s important to not undermine the work of the past, because that’s going to create a lot of regulatory uncertainty,” she said.

If the initiative is approved, the work would be assigned to a task force, Perera said.

Light-Load Analysis

PJM has compiled some data to begin updating parameters for modeling light-load conditions. PJM’s Mark Sims presented the data.

“There’s definitely plenty of activity happening out there to draw some conclusions,” he said.

One focus is comparing high-voltage alarms with instances when high-voltage emergency procedures were taken. The alarms, which require generators receiving them to take action, precede emergency procedures that PJM takes.

“The alarm data is a good proxy to use moving forward to look for statistical values to develop parameters” for a test, Sims said.

PJM is also considering how to address the lag between recognizing an issue and compiling all the information to address it effectively.

“Between it happening and us fixing it, it could be a couple of years,” Sims said.

Summer Demand less than Expected

Mild weather meant load never came close to reaching the peak summer forecast, PJM’s John Reynolds said.

The summer peak of 145,331 MW on July 19 was 5% below the forecasted peak of 152,999 MW and 4.4% below the 2016 peak of 151,945 MW. “The champ still reigns,” Reynolds said, referring to PJM’s all-time peak of 166,876 MW on Aug. 2, 2006.

There were 0.4 MW of load management July 19, he said, and there have been anecdotal accounts of a “significant amount” of peak shaving this summer.

The decline in weather-normalized load won’t mean an immediate drop in load forecasts.

“That would be an assumption that people should not make,” Reynolds said. “It will take time for that to work its way in full.”

The call for patience confounded Calpine’s David “Scarp” Scarpignato.

“I don’t want to wait 18 years to get the forecast right,” he said.

ARR Analysis IDs Constraints

An analysis of Stage 1A 10-year auction revenue rights found “infeasible facilities” both within PJM’s footprint and in market-to-market interactions with MISO, Perera said.

The internal constraint will be addressed by a project (b2774) in the Regional Transmission Expansion Plan, which is expected to be in service in 2020. Of the remaining nine M2M constraints, one will be addressed by a MISO Transmission Expansion Plan project that is expected to be in service this year. Three others have projects under consideration, two will be included in a future targeted market efficiency project proposal window and three are pseudo-tie flowgates.

Asked specifically about lines connecting to the Ohio Valley Electric Corp. — which is attempting to join PJM as a transmission zone — Perera said no new issues were identified. A project between OVEC’s Clifty Creek Power Plant and the Trimble County substation is one of nine M2M constraints under consideration.

— Rory D. Sweeney

November 14, 2017

PJM’s Markets Competitive, Energy Prices Up, Monitor Finds

By Rory D. Sweeney

PJM’s markets were competitive in the first nine months of the year and energy prices were up $1/MWh compared to the same period last year, the Independent Market Monitor found in its quarterly State of the Market Report.

“Energy prices in PJM in the first nine months of 2017 were set, on average, by units operating at, or close to, their short-run marginal costs, although this was not always the case during high-demand hours,” the report said. “This is evidence of generally competitive behavior and resulted in a competitive energy market outcome.”

state of the market report — Quarterly total price and quarterly inflation adjusted total price ($/MWh): January 1, 1999 through September 30, 2017 | *Monitoring Analytics*

The load-weighted, average LMP in PJM was 3.5% higher in the first nine months of 2017 than during the same period in 2016, rising to $30.36/MWh. The Monitor said the increase was “primarily” due to higher fuel prices.

Coal and natural gas costs rose faster than electricity prices, undercutting generator revenues. Average energy market revenues decreased by 51% for new gas-fired combustion turbines, 28% for new combined cycle units and 17% for a new coal plant, while increasing 6% for nuclear units, the Monitor said.

Coal units’ dominance has dipped over time, while gas has risen. In 2008, coal represented 75% of the marginal resources and gas 20%. In the first nine months of this year, coal stood at 32.5% and gas rose to 52.9%, the Monitor said.

Wind continued to depress prices as the marginal unit. In the first nine months of 2017, 74.1% of the wind marginal units had negative offer prices, 18.9% had zero offer prices and 6.9% had positive offer prices.

Total energy uplift charges decreased $16 million (15.7%) to $86.3 million during the nine-month period. Demand response payments also decreased by $167.2 million (31.1%) to $370.6 million, while congestion costs fell $366.8 million (44.6%) to $455.4 million.

The impact of FERC’s ruling on balancing congestion — rejecting the notion that financial transmission rights are only intended to benefit load — was also evident this year. Revenues from auction revenue rights and FTRs offset 98.1% of total congestion costs for load during the 2016/2017 planning period, but only 79.7% of those costs for the first four months of the 2017/2018 planning period. In January, FERC accepted PJM’s compliance filing in response to the commission’s requirement that the RTO develop a method for allocating ARRs that doesn’t consider extinct generators. Under the new rules, PJM assigns balancing congestion to real-time load and exports and regularly updates its ARR allocations to reflect generator retirements. (See FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)

November 13, 2017

FERC Rejects SPP Change on Network Resource Upgrades

By Rich Heidorn Jr.

FERC last week issued rulings in three SPP transmission cases, mostly siding with the RTO but rejecting its proposal to change the conditions for classifying service upgrade costs for designated resources.

SPP’s Tariff allows service upgrades associated with new or changed designated resources to be classified as base plan upgrades, subject to regional cost allocation, if the load-serving entity’s resulting capacity does not exceed 125% of its projected system peak responsibility.

SPP said its proposed wording changes clarify and update its rules and have “no practical or detrimental effect” on its study process.

The commission disagreed, saying the proposed Tariff language was inconsistent with SPP’s representation of how it calculates customers’ “highest hourly load” (ER17-1795).

It also took issue with the RTO’s plan to calculate “highest hourly load” on an aggregate basis for network customers with multiple service agreements that include the same designated resources. The commission said SPP had not proven that its proposal was not unduly discriminatory to customers with multiple agreements that do not include the same designated resources.

Z2 Waiver Upheld

The commission denied rehearing requests on its July 2016 order waiving the one-year limit for adjusting payment obligations and revenue distributions for transmission projects under Tariff Attachment Z2. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)

SPP FERC KEPCo upgrade costs — Member Coops | *Kansas Electric Power Cooperative*

FERC said the challengers — American Electric Power, Xcel Energy, Kansas Electric Power Cooperative (KEPCo) and Southern Co. — incorrectly applied the commission’s criteria for granting waivers (ER16-1341-001).

“Specifically, the arguments made on rehearing conflate the waiver’s scope (i.e., the provisions to be waived) with its potential consequences,” FERC said. “The parties on rehearing also ignore the waiver’s purpose because they assert that SPP must demonstrate that it will implement the crediting mechanism correctly before the waiver can be granted. The purpose of the waiver is to remove barriers to implementation. The process of implementation itself is beyond the scope of this proceeding.”

Split Decision in KEPCo Dispute

The commission partially granted KEPCo’s November 2016 complaint in a separate transmission dispute with SPP (EL17-21). The commission also denied some claims and set settlement judge procedures on others.

FERC rejected KEPCo’s allegation that SPP inappropriately directly assigned the cooperative $6.2 million in costs for network upgrades in violation of four network integration transmission service (NITS) agreements and the filed rate doctrine.

“Even though the NITS agreements did not list any network upgrades for which KEPCo would be directly assigned cost responsibility, KEPCo knew that … there may be possible Attachment Z2 revenue credit payment obligations and also that SPP was in the process of developing the [Crediting Process Task Force] white paper, with a methodology that would identify the network upgrades with more certainty,” the commission said.

FERC also rejected KEPCo’s claim that SPP’s allocation of upgrade costs was made too late under its Tariff. “To the extent SPP’s original analysis did not capture certain creditable upgrades, we also find it is reasonable to permit SPP to make corrections to the list of network upgrades so that upgrade sponsors are compensated for transmission service that their sponsored upgrades have facilitated, and which KEPCo has received,” it said.

SPP also prevailed on KEPCo’s claim that it violated the “but for” test in directly assigning costs for certain network upgrades.

The commission agreed with KEPCo that SPP had “improperly applied” its cost allocation rules in one instance but said the violation had no impact on the costs allocated to the cooperative.

Finally, FERC set hearing and settlement judge procedures to resolve whether KEPCo’s transmission service requests had a material impact on the Rice-Circle transmission project — a new Rice substation and an upgrade of the 28-mile line between it and the Circle substation to 230 kV from 115 kV.

“The specific issue is whether, according to a transfer distribution analysis, KEPCo’s transmission service requests cause at least a 3% impact on the Rice-Circle facility, and therefore, are considered to impact the facility and should be assigned costs for that facility,” the commission said.

— Tom Kleckner contributed to this article.

November 13, 2017

MISO Seeks to Gauge Risk of Peak Season Planned Outages

By Amanda Durish Cook

CARMEL, Ind. — Facing an increased number of outages from an aging fleet of baseload generators across the footprint, MISO officials are examining how they can capture the risk of planned and maintenance outages occurring during peak load.

maintenance outages miso peak load — Westphal | © *RTO Insider*

Ryan Westphal, MISO resource adequacy coordinator, said an investigation by the RTO’s Loss of Load Expectation Working Group suggests a need to account for intentional outages, but stakeholders have not yet reached consensus on how to proceed.

“Every year [since 2012], we saw some number of both planned and maintenance outages that happen on peak,” Westphal said during a Nov. 8 Resource Adequacy Subcommittee meeting.

Westphal said MISO has looked into incorporating a combined average volume of planned and maintenance outages into its loss-of-load-expectation (LOLE) calculation, which would bump up the RTO’s predicted 17.1% planning reserve margin by about 0.4% in the 2018/19 planning year. The increase would lead to an additional 600 MW being cleared in this year’s capacity auction, MISO estimated.

MISO currently does not model any planned and maintenance outages at peak load, assuming such outages are optimized and not occurring during peak demand, but the RTO may want to revise its LOLE study to include the probability that some outages will occur during the peak, Westphal said.

“It leads us to think that all the risk isn’t being captured in our planning reserve margin today,” he said. Over the last several years, MISO has carried a sufficient reserve margin to cover outages that occur on peak, he added.

During July 2016, MISO experienced about 3.4 GW of planned outages and 1.8 GW of maintenance outages. The following month saw planned and forced outages of 2.4 GW and 4.2 GW, respectively. While those outages combined were nowhere near the volume of forced outages in the summer (12 GW in July, 10 GW in August), they helped nudge total outages above 16 GW during both months, a benchmark that was surpassed only once before in August 2015.

Duke Energy’s Brian Garnett asked how a maintenance outage occurs that’s not already planned or forced.

MISO defines maintenance outages as less severe mechanical issues that don’t result in an immediate outage trip but must be scheduled for repairs, Westphal said.

Indianapolis Power and Light’s Ted Leffler asked if the new calculation will be applied universally across the footprint or target individual units.

“I would caution that not every generation unit that has planned outages has load,” Leffler said.

Westphal said MISO would discuss the proposal again next month, and asked stakeholders to send written feedback before the Thanksgiving holiday.

November 13, 2017

MISO Stands by Load Forecast Confirmation Method

CARMEL, Ind. — MISO is defending its methods for validating utility load forecasts after Dynegy last month charged that Ameren Illinois miscalculated its summer peak load forecast.

Michael Robinson, MISO principal adviser of market design, said the RTO’s Tariff obligates it to draw a random sample of load-serving entity demand forecasts to “assess credibility” of the forecasts. For the LSEs selected for the sample, MISO performs an ex post review of their previous year’s forecast and works with them to reconcile differences between their forecasts and those produced by Purdue University’s State Utility Forecasting Group.

MISO FERC Dynegy summer peak Ameren — Left to right: Mike Robinson with RASC Chair Chris Plante and RASC liaison Shawn McFarlane | © *RTO Insider*

“Ameren was a draw in the random sample last year,” Robinson confirmed at a Nov. 8 Resource Adequacy Subcommittee meeting. “We did have to come back and ask them for additional documentation. Some of their documents were a bit sketchy, I guess, but they gave us everything we needed.”

Last month, Dynegy called on MISO to develop a new process for verifying load forecasts produced by LSEs, claiming Ameren’s forecasts led to under-procurement in the capacity auction for Zone 4. (See Dynegy: MISO LSE Load Forecasts Require Tune-up.)

MISO said it found no evidence of systemic bias in forecasts. Robinson said Zone 4 was slightly hotter than normal at coincident peak this summer and all local resource zones were within two standard errors of their forecast values.

“The way we design this is the LSEs are the experts in the sense that they know when customers are building. They certainly have more information than we do,” Robinson said. “We don’t forecast ourselves on the zonal level for the coincident peak. We don’t have that kind of information.”

— Amanda Durish Cook

November 13, 2017March 25, 2025

Chatterjee to Push Interim ‘Lifeboat’ for Coal, Nukes

By Rich Heidorn Jr.

FERC Chairman Neil Chatterjee said last week he will seek an interim “lifeboat” to ensure the survival of struggling coal and nuclear plants while the commission ponders long-term rule changes.

FERC ISO-NE Cheryl LaFleur Neil Chatterjee

Chatterjee | © RTO Insider

He laid out his plans in remarks at an industry conference and in an interview Thursday on Bloomberg television.

Chatterjee has said the commission will take action by Dec. 11 on Energy Secretary Rick Perry’s call for “full recovery” of coal and nuclear plants’ costs in RTOs with energy and capacity markets, including PJM, ISO-NE and NYISO. More than 700 comments were filed in response to the Department of Energy’s Notice of Proposed Rulemaking (RM18-1). (See NOPR Backers, Foes Seek Last Word at Comment Deadline.)

In a meeting with reporters last month, Chatterjee said FERC’s options include initiating its own rulemaking, convening a technical conference or issuing a final rule based on DOE’s NOPR.

Now, facing legal and political obstacles to winning approval of a final rule, Chatterjee said he is seeking a short-term plan to rescue as many plants as possible while the commission does additional fact-finding.

“What I don’t want to have is plants shut down while we’re doing this longer-term analysis, so we need an interim step to keep them afloat,” Chatterjee told the S&P Global Platts Energy Podium in D.C. “I don’t know that we can get everybody in the lifeboat,” he added.

“My approach is going to be one of no regrets,” he said in the Bloomberg interview. “The worst-case scenario would be we do the long-term analysis, we figure out we actually did need these plants, but they’re gone. They’re offline and we can’t get them back.”

He said his plan will not alter RTO dispatch practices or distort markets.

Jones | FirstEnergy

Chatterjee also disclosed he had met with FirstEnergy CEO Chuck Jones “to really kick the tires on what they proposed [in their comments on the DOE NOPR] and challenge them on some of what they had put forward.” FERC’s ex parte rules, which bar commissioners from private discussions with parties in “case-specific, contested proceedings,” do not apply to rulemakings, according to a 2010 presentation by FERC Associate General Counsel Lawrence R. Greenfield (18 CFR 385.2201(a), (b), (c)(1)(ii)).

FirstEnergy proposed that the commission require RTOs and ISOs adopt a pro forma Resiliency Support Resource (RSR) tariff agreeing to make monthly payments to “fuel-secure, resilient generators.” The payments would be “equal to its full costs of operation and service” and a “and a fair return on equity,” minus its revenues for capacity, energy and ancillary services.

Chatterjee, a native of coal state Kentucky and a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), has made no secret of his desire to aid coal generators. Commissioners Robert Powelson, a Republican, and Cheryl LaFleur, a Democrat, have reacted more warily to the Perry proposal, expressing concern it could damage wholesale markets.

Republican Kevin McIntyre and Democrat Richard Glick, who were confirmed to FERC by the Senate on Nov. 2, are awaiting their swearing-in and have not commented publicly on the proposal. Chatterjee told Bloomberg that he had not discussed the NOPR or his interim proposal with McIntyre, who will replace him as chairman.

“Kevin is somebody with a lot of expertise. He’s a smart, thoughtful guy. … And I hope that he will ultimately be persuaded to follow the course that I’ve laid out,” Chatterjee said.

Perry’s Sept. 28 proposal requested that FERC issue a final rule within 60 days. But even if Chatterjee won the two additional votes he needs to approve a final rule in December, it could be vulnerable to court challenges on the grounds that it was rushed through without sufficient notice to the public and proper evaluation by the commission.

November 13, 2017

FERC to Examine DTE Reactive Rate Reduction

FERC last week opened a fresh settlement proceeding to determine the fairness of DTE Electric’s decreased revenue requirement for reactive power services, an issue already under scrutiny by the agency (ER17-2465).

DTE in April asked the commission to approve an $11 million annual revenue requirement for reactive supply in the ITC transmission pricing zone, down 14% from the current $13 million requirement (ER17-1414). The Detroit-based utility submitted the revised request in September to account for an additional $118,000 decrease stemming from the Nov. 14 retirement of St. Clair Unit 4, an aging coal-fired generator. The first request had been under settlement proceedings for four months by the time of the second filing (EL17-71).

FERC MISO revenue requirement DTE — St. Clair Power Plant | *Inland Mariners*

The company cited seven retirements, increased investments in generation units that provide reactive service, and the replacement of its total revenue requirement with unit-specific revenue requirements as reasons behind the rate decrease.

FERC said preliminary analysis shows that DTE’s rate schedule may still be unreasonable even with the $118,000 decrease, and consolidated the newly opened settlement proceeding with the existing one under a new docket, EL18-23.

“Because DTE Electric is proposing a rate reduction, but a further rate decrease may be appropriate, we will institute a Section 206 proceeding,” FERC wrote.

— Amanda Durish Cook

November 13, 2017

FERC OKs SPP Scarcity Pricing Change

By Rich Heidorn Jr.

FERC last week approved SPP’s proposal to change the way it prices regulation and operating reserves but said the RTO should respond to complaints that it overuses out-of-market procedures to avoid scarcity pricing.

The ruling, effective May 11, 2017, finalized a tentative approval granted by FERC staff in August before the commission regained its quorum (ER17-1092).

The changes were in response to FERC’s June 2016 ruling (Order 825) requiring RTOs and ISOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period. (See FERC Issues 1st RTO Price Formation Reforms.)

SPP previously set a single administrative scarcity price for each reserve product regardless of the severity of a shortage. Under the new rules, the RTO will use segmented demand curves with higher degrees of scarcity resulting in higher prices. It is also renaming its operating reserve demand curve as the contingency reserve demand curve.

In approving the changes, the commission rejected a complaint from Golden Spread Electric Cooperative that the regulation demand curves should begin with a steeper slope to incentivize units to provide regulation earlier.

“We find that SPP has supported the structure of the proposed contingency reserve demand curve, which is based on NERC requirements for SPP to carry reserves to protect against loss of the largest online resource in its footprint and based on the contingency reserve the [Reserve Sharing Group] procures to protect against the loss of half of the second largest online resource in the SPP footprint,” FERC said.

However, it directed SPP to add to its Tariff definitions and other details of the new rules, which the RTO had planned to include in its Marketplace Protocols. “The commission has found that provisions that are used to calculate a rate should be included in the Tariff because they significantly affect rates, terms and conditions of service,” the order said.

The commission also rejected Golden Spread’s complaint that SPP has prevented the implementation of shortage pricing by overusing out-of-market actions such as reliability unit commitments and manual commitments.

FERC SPP scarcity pricing — Golden Spread Electric Cooperative complained that SPP’s shortage pricing rules are insufficient, depressing prices for plants that can respond quickly to scarcity conditions. Its Antelope Station, near Abernathy, Texas, can reach its full 168-MW output in five minutes. | *GSEC*

Although the commission said Golden Spread’s call for market design changes regarding such actions was outside the scope of the proceeding, it said the cooperative had “raised an important issue that SPP should consider exploring through its stakeholder process.”

“We understand that there may not be sufficient data available to stakeholders to facilitate these discussions, as the commission noted in its Notice of Proposed Rulemaking in Docket No. RM17-2,” the commission said, referring to its January 2017 proposal to reduce uplift, allocate it more accurately and increase transparency. (See FERC Seeks More Transparency, Cost Causation on Uplift.)

“While further commission action in Docket No. RM17-2 may result in additional transparency, we encourage SPP to work with its stakeholders and provide them with the data necessary to aid in any discussions about this issue.”

November 13, 2017May 15, 2025

Early Adopter Pa. Worried by Retreat from Competitive Markets

By Rich Heidorn Jr.

CAMP HILL, Pa. — Pennsylvania, which was among the first states in the U.S. to abandon cost-of-service electric regulation, now finds itself at ground zero of a debate that could largely reverse the process. So last week’s 7th Annual Pennsylvania Energy Management Conference couldn’t have been more timely.

FERC Chief of Staff Anthony Pugliese, who grew up just a few miles from here, praised the Department of Energy’s Notice of Proposed Rulemaking to support struggling coal and nuclear generators, while promising it would not destroy PJM’s competitive market.

Exelon’s Kathleen Barron continued her ongoing debate with NRG Energy and other critics over subsidies for the company’s nuclear plants. (See EBA Panelists Talk ‘Wacky’ NOPR, ‘Modest’ ZECs, ‘Rent Seeking’.)

And PJM Independent Market Monitor Joe Bowring, who shared a panel with Barron and NRG’s Abe Silverman, continued his attack on the RTO’s proposed alternative. (See related story, NOPR Reply Comments Bring More Criticism of PJM Proposal.)

Stranded Costs

Pamela C. Polacek, an attorney with McNees Wallace & Nurick, one of the conference’s sponsors, joined in the criticism. Her firm has long represented industrial customers and was central to Pennsylvania’s move — following California and Massachusetts — to customer choice in 1996.

Pennsylvania consumers paid $12.3 billion in stranded costs to Exelon’s PECO Energy and other nuclear plant owners between 1996 and 2010 as part of the bargain to unbundle generation from distribution. Polacek said subsidies for all of Pennsylvania’s nuclear plants could cost $1.2 billion per year — raising the annual electric bill for a small industrial user (12 million kWh/year) by more than $100,000, and that for a steel mill (330 million kWh/year) by $2.8 million.

“We can’t afford this in Pennsylvania,” she said. “We rank 48th in manufacturing job creation. … We can’t continue to pile costs onto our industrials. Right now, our average industrial electric rate is about the middle [of the states]. But remember, we did this [retail choice] back in 1996 to get competitive advantage, not just to be in the middle.”

Polacek said Three Mile Island Unit 1, the only planned nuclear retirement in Pennsylvania, doesn’t deserve a rescue.

“As Joe has said, other Pennsylvania nuclear plants continue to clear the [capacity] auction. For the most part, they are not at risk of retirement.”

Investment

She acknowledged that as a single-reactor plant (following the partial meltdown of Unit 2 in 1979) TMI does not have the labor economies of scale of multi-unit plants. But she said saving TMI’s 750 workers would cost jobs in manufacturing because of higher electric rates.

“Three Mile Island didn’t really take the opportunities to do upgrades that other Pennsylvania-based plants did. So those plants were looking at investing in their infrastructure to expand their capacity, to be more efficient. And Three Mile Island didn’t do that.”

Exelon, which purchased the plant from GPU in 1999, said in May it would shutter TMI in September 2019 “absent needed policy reforms.” (See Seeking Subsidy, Exelon Threatens to Close Three Mile Island.)

Barron disputed Polacek’s claim of underinvestment. “I can tell you we continue to invest very heavily in Three Mile Island, having replaced the steam generator … and [made] other investments,” she said.

She cited a Brattle Group study that predicted early retirement of the state’s nine nuclear generators would increase prices by $788 million per year, a 5% increase.

Resilience

The two also sparred over nuclear power’s value to the grid’s resilience.

“Looking at the idea of having onsite fuel supply as being something that is going to help us if all four gas pipelines serving the Northeast go down, I have to ask: Well if the terrorists do that, what’s going to stop them from also targeting the nuclear plants, which would seem to be a pretty attractive, World Trade Tower-type targets?” Polacek said.

Barron said nuclear plants’ defenses against terrorists are second to none. “We are so heavily regulated by a number of regulators, including the [Nuclear Regulatory Commission], on this specific point, on the amount of security we have to have in our plants and the ways that we need to protect them,” she said. “There are more people who [are carrying] guns than people who are operating the plant. … We do not have anywhere near that kind of protection on the natural gas supply system.”

That is beside the point, responded Bowring, saying the vulnerabilities of gas pipelines also apply to electric transmission. “It doesn’t matter what the fuel type is if the transmission grid is not there,” he said. “So, you have to be careful how far you extend this argument.”

ZECs

ZEC DOE 7th Circuit Court of Appeals PJM 2015 Annual Meeting — Silverman | © *RTO Insider*

NRG’s Silverman said that he agreed with the DOE on the need for price-formation reforms. But he said zero-emission credits for nuclear plants are not a good solution. ZEC prices in New York and Illinois will produce half as much carbon-free electricity as equivalent spending on renewables, he said.

He was critical of a Brattle study commissioned by NYISO and state regulators to evaluate the impact of ZECs. (See NYISO Study Sees Little Cost Impact from Carbon Charge.)

“It completely ignores the energy market response. Completely ignores the power of competition to find cheaper solutions and drive down the price,” he said.

“We have these price-formation initiatives at FERC that have now been pending, in some cases, for four or five years. They need to be acted on. I mean come on guys, yes or no.”

And he said the issue is broader than price formation. The challenge, he said, is creating incentives for what NRG calls the “four-product future,” which envisions renewables providing most energy, supported by storage, controllable demand and fast-ramping gas. NRG says it will reduce the carbon emissions from its generation 50% by 2030 and 90% by 2050.

“A [gas-fired] power plant built today is already going to be lasting until 2050 and [will] be emitting too much carbon” to address climate change, Silverman said. “So, we end up with this long-term stranded cost environment where today’s gas plants are tomorrow’s coal plants.”