Those of us who dwell in the economic/regulatory/public policy realm wonder about the origins of atrocious public policy. Where did it come from? Whose awful idea was this?
In the case of the Department of Energy’s Cash for Clunkers proposal, we pretty much know.
Robert Murray, owner of the coal mining company Murray Energy,[1] was a large fundraiser for candidate Donald Trump during the campaign.[2] After the election, Murray had a couple of meetings with President Trump at which the president promised Murray to do whatever he (and FirstEnergy) wanted Trump to do. I’m not making this up.[3]
What Murray wanted was for Rick Perry, the secretary of energy, to declare an emergency on the electric grid so that FirstEnergy would keep buying a lot of coal from Murray’s coal mining company. Again, I’m not making this up.
Now it seems that pesky government lawyers figured out that the supposed basis for such an action, Section 202(c) of the Federal Power Act, couldn’t possibly justify that. “The White House and the Department of Energy are in agreement that the evidence does not warrant the use of this emergency action.”[4]
At this point, a lot of us naively assumed it was safe to go back about our business. We were wrong.
Somebody came up with Plan B (or more like Plan 9) of using an even more obscure federal statute to tell FERC to have a rulemaking to subsidize the coal and nuclear clunkers in the country. So here we are.
FERC on Friday accepted ISO-NE’s updated cost of new entry (CONE) and offer review trigger price (ORTP), effective March 15, 2017 (ER17-795).
The RTO, which is required to recalculate the values every three years, will apply the revisions in Forward Capacity Auction 12 in February 2018 for the June 2021–May 2022 capacity commitment period, as well as in FCAs 13 and 14.
In its Oct. 6 order, the commission agreed with ISO-NE on every point and refuted every protest filed by the New England Power Generators Association (NEPGA). The RTO changed the reference resource on which it bases the CONE and net CONE values from the combined cycle gas turbine chosen in 2014 to a simple cycle generator, citing it as the most economically efficient, with a net CONE value of $8.04/kW-month. The grid operator cited the combined cycle turbine as the next most efficient resource type, with a net CONE of $10/kW-month.
| ISO-NE
NEPGA argued that zonal clearing prices in FCAs 7-9 were at or above $14.99/kW-month, which indicated that the actual CONE is higher than ISO-NE’s proposed value. The commission disagreed, saying “NEPGA has not persuaded us that the proposed net CONE value will result in a starting price that will limit investment and competition in the FCA.”
Regarding NEPGA’s comment that ISO-NE’s consultant on the Tariff revisions, Concentric Energy Advisors, listed a production tax credit value as 15 cents/kWh, rather than 1.5 cents/kWh, the commission noted that “this appears to be a typographical error that is not carried forward into Concentric’s calculation of the actual ORTP value.”
The commission also approved ORTP values of $7.856/kW-month for combined cycles, $6.503/kW-month for combustion turbines, $11.025/kW-month for onshore wind, $0/kW-month for energy efficiency, $1.008/kW-month for large demand response and $7.559/kW-month for mass-market DR. Offers below the technology-specific thresholds are subject to review by the RTO’s Market Monitor for buyer-side market mitigation.
FERC on Friday approved NYISO’s more stringent testing requirements for generators providing black start and system restoration services (ER17-2271). The changes, effective Oct. 8, require that generators participating in the Consolidated Edison local system restoration plan comply with all applicable testing requirements imposed by mandatory reliability standards.
The New York State Reliability Council (NYSRC) last November approved proposed reliability rule 133, which requires that all generators providing restoration services annually test their ability to energize a dead bus without support from the transmission system. NYSRC coordinates its reliability rules with NERC and the Northeast Power Coordinating Council.
New York skyline when half the city was in blackout due to a power failure during Hurricane Sandy in 2012. Midtown, with the Empire State Building, is in the background with the darkened East Village and other parts of downtown in the foreground.
Con Ed in 2016 became a NERC-registered transmission operator and must comply with NERC reliability standard EOP-005-2.3.
The commission’s Oct. 6 order dismissed a protest from NRG Energy that the proposed change would give Con Ed “sole discretion to change black start testing rules at any time, without NYISO stakeholder or commission review, or adequate notice to affected generators.” NYISO had responded to NRG that any changes to its System Restoration Manual are subject to review by stakeholders, posted for review at least 15 days prior to a scheduled committee approval and must be approved by 58% of voting members of the applicable committee.
FERC agreed: “Of note, in this case, NYISO stakeholders have already reviewed and unanimously approved revisions to the System Restoration Manual that include specific black start testing requirements in the Con Edison plan.”
LS Power’s Republic Transmission last week won FERC approval for incentives to construct MISO’s first competitively bid transmission project.
FERC granted Republic’s requests for a return on equity adder of 50 basis points for participating in an RTO for the Duff-Coleman transmission project. The commission also approved the company’s request for recovery of prudently incurred costs if the project is abandoned for reasons beyond Republic’s control and use of a hypothetical 55% debt/45% equity capital structure until commercial operation (EL17-52).
Duff to Coleman planned route in yellow | Republic Transmission
FERC noted that its approval of the adder is subject to the overall 9.8% on ROE cap Republic promised in its project proposal.
FERC backdated the rate approval to May 15. While FERC was without a quorum for six months, Republic begun developing the Duff-Coleman project under the assumption that it would receive all requested incentive rates.
“Republic’s investors entered into the selected developer agreement and agreed to rate concessions with an expectation that the project would qualify for, and receive, the limited incentive rates requested prior to the expenditure of significant funds,” FERC said. The commission also found that MISO’s 2015 Transmission Expansion Plan established that the project will deliver cost benefits by relieving congestion and improving reliability, a requirement of incentivized rates under Order 679, which established incentive-based rates for transmission development over a decade ago.
Duff to Coleman route in red near Ohio River | Republic Transmission
For the remainder of 2017 and most of 2018, Republic will work on project design, environmental permitting and securing rights of way. Construction is slated to begin the fourth quarter of 2018.
Republic said it expects to encounter “construction risks and challenges,” most notably acquiring federal permitting to cross the Ohio River.
FERC on Friday rejected a bid by New England transmission owners to increase their returns on equity to the levels enjoyed before they were lowered by a 2014 commission order that was vacated by an appellate court earlier this year.
The commission said it would address the actual rate in a later remand order (ER15-414, EL11-66).
The D.C. Circuit Court of Appeals ruled in April that the commission had “failed to provide any reasoned basis” for setting the base ROE for a group of New England TOs at 10.57%, adding that the commission failed to meet its burden of proof in declaring the existing 11.14% rate unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)
National Grid’s Sandy Pond Substation in Ayer, Mass.
Led by Emera Maine, the TOs requested reinstatement of their previously allowed ROEs in June. Other parties included Central Maine Power, Eversource Energy, National Grid and Avangrid subsidiary United Illuminating.
The TOs claimed that the court’s decision “automatically” restored the parties to the rate in effect prior to the vacated Opinion No. 531. Because the commission lacked a quorum at the time of the filing, the TOs asked to begin collecting at the higher rate 60 days after the commission regained a quorum, which it did on Aug. 9, when new Chairman Neil Chatterjee and Commissioner Robert Powelson joined the commission. (See Quorum Restored, FERC Holds First Open Meeting Since January.)
To reduce the administrative burden on the commission, the TOs said they would leave the question of surcharges for the period before the court’s decision until FERC issued a remand order for Emera.
| ISO-NE
The commission disagreed that the D.C. Circuit decision returned TOs to their previous ROEs: “As the Supreme Court explained in Burlington Northern Inc. v. United States, which involved the substantively similar provisions of the Interstate Commerce Act, a ‘federal court[’s] authority to reject … rate orders for whatever reason extends to the orders alone, and not to the rates themselves.’”
The commission concluded that leaving the current ROEs in place would not make the TOs any worse off following a remand order for Emera because, on remand, the commission will exercise its “broad remedial authority” to make whatever ROE the commission determines to be just and reasonable effective for the refund period and the entire period.”
In addition, the order said an immediate return to the previously allowed ROEs would “significantly complicate the process of implementing the commission’s order on remand.”
In 2014, FERC determined that a discounted cash flow (DCF) analysis of a proxy group of companies comparable to TOs produced a zone of reasonableness of 7.04 to 11.74%. The commission also concluded that TOs’ new just and reasonable ROE should be set at the upper midpoint of the zone of reasonableness — i.e., halfway between the midpoint and the top of the zone of reasonableness.
The D.C. Circuit ruled that the commission had not adequately shown that the existing ROE was unjust and unreasonable. The court explained that the Federal Power Act’s statutory “zone of reasonableness creates a broad range of potentially lawful ROEs rather than a single just and reasonable ROE.”
SPP stakeholders last week briefly discussed a recent American Electric Power complaint filed at FERC against the RTO and MISO related to overlapping congestion charges for pseudo-ties.
The Section 206 complaint (EL17-89) alleges that MISO violated its joint operating agreement with SPP by assessing congestion charges to AEP subsidiary Southwestern Electric Power Co. load that is pseudo-tied out of MISO and into SPP.
In its complaint, AEP said the MISO Tariff and Business Practices Manual are unjust and unreasonable in how they assess the congestion charges.
SPP and MISO have negotiated a memorandum of understanding to address the overlapping charges. The RTOs have said the MOU borrows elements from MISO’s coordination efforts with PJM but won’t result in major changes in coordination. (See MISO Interregional Plans with SPP Echo PJM Efforts.)
Staff said Friday it will file a response at FERC but won’t comment until then.
Light M2M Activity Results in $161K in Payments to SPP
In what staff described as a light month for market-to-market activity between SPP and MISO, the latter paid SPP more than $161,000 in August, reversing two months of payments in the opposite direction.
| SPP
Permanent flowgates accounted for most of the congestion, binding for 37 hours and resulting in $148,794 in M2M settlement charges to MISO. Temporary flowgates were binding for 83 hours, 131 hours less than the month before, giving SPP an additional $12,495.
SPP has collected $20.7 million in payments from MISO as of August. The M2M process between the two RTOs began in March 2015.
AEP’s Jacoby Continues as Chair
The committee approved its recommendation for AEP’s Jim Jacoby to serve a full two-year stint as chairman, effective Jan. 1. Jacoby’s term will expire Dec. 31, 2019.
FERC on Friday rejected SPP’s proposed cost allocation for its seams project with Associated Electric Cooperative Inc. (AECI), a Missouri-based collection of six generation and transmission cooperatives.
The commission ruled SPP had not shown that the proposed allocation on a regionwide, load-ratio share basis was “roughly commensurate” with the project’s benefits (ER17-2256, ER17-2257).
The project includes a new 345/161-kV transformer at AECI’s Morgan substation and uprating a related 161-kV line, both near Springfield, Mo. SPP estimated the project, intended to address persistent thermal and voltage problems, would cost $18.75 million. SPP asked FERC to approve a cost-sharing and usage agreement among the RTO, AECI and City Utilities of Springfield — along with Tariff revisions incorporating SPP’s negotiated share of the revenue requirements — in August.
| AECI
SPP General Counsel Paul Suskie said that although the RTO is disappointed, “we’re undeterred and confident we’ll be able to continue to work … with members to develop an appropriate cost allocation for this and future seams projects.”
“The ability to develop necessary and beneficial transmission improvements along our seams remains a high priority for SPP and its members,” Suskie added.
SPP had proposed to regionally fund the projects, as they solved congestion issues on its side of the seam. The RTO agreed to cover 89.1% of the $13.75 million transformer and 97% of the $5 million uprate, with AECI covering the remainder and being responsible for the projects’ construction, operations and maintenance.
The RTO said it planned to allocate its share of the two projects by inserting their revenue requirements into the annual transmission revenue requirement of its highway/byway regional cost allocation methodology. Highway/byway funding considers facilities of 300 kV or above as highway facilities, with their costs allocated on a regionwide, postage-stamp basis; facilities between 100 and 300 kV are categorized as byway facilities, with two-thirds of the costs assigned to the host zone and one-third allocated regionwide.
Projects below 100 kV are allocated entirely to the host zone, while upgrades that operate at two difference levels — such as transformers — are allocated based on the facilities’ lower operating voltage.
Xcel Energy and Westar Energy protested the RTO’s filing.
Xcel opposed the Morgan transformer’s cost allocation, contending that SPP provided insufficient evidence that the proposed cost allocation reflects its benefits. The company said there is no “default rule” that customers in SPP’s 19 transmission zones “should bear the costs of a transmission facility in cases where the owner of the facility is located outside [the footprint].”
| SPP
The company also said SPP failed to provide information on the project’s benefits to transmission owners or loads in the Southeastern Regional Transmission Planning (SERTP) region that would justify a broader cost allocation to AECI’s fellow SERTP members.
FERC sided with Xcel’s argument that SPP had not provided specific information on the transformer project’s regionwide benefits and had not offered “sufficient evidence to demonstrate that these claimed economic benefits accrue throughout the SPP footprint.” The commission said the RTO’s own analysis indicated the project does not provide economic benefits to at least 11 of the 19 transmission zones.
Because SPP failed to support its cost allocation, FERC said it did not need to address Westar’s allegation of a lack of transparency regarding SPP’s negotiations with AECI. The utility had argued all affected parties have a right “to analyze the methodology and rationale by which SPP and AECI negotiated and substantiated the cost allocation ratios proposed in the filings.”
The commission said its rejection does not preclude the RTO from proposing an alternative allocation or making another filing that demonstrates the project provides regional benefits.
SPP stakeholders in July reiterated their support of the project, despite a nearly 50% cost increase due to additional work to upgrade the 161-kV line. (See “Board Reaffirms Seams Project with AECI,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)
The commission in 2015 rejected SPP’s attempt to create a new class of seams transmission projects, saying its plan to identify projects outside the Order 1000 interregional planning process was “too broadly drawn” (ER15-2705). FERC did allow SPP to make filings on a project-by-project basis for non-Order 1000 facilities. (See FERC Rejects SPP Proposal for Seams Transmission Projects.)
BOSTON — The transmission projects proposed to bring renewable energy to New England all promise fixed-cost contracts, hundreds of jobs, big cuts in CO2 emissions, and millions in consumers savings and tax revenues.
How to choose? That was the question Friday at Raab Associates’ New England Electricity Restructuring Roundtable.
Representatives of five transmission projects proposed in July in response to the Massachusetts solicitation for 9.45 TWh/year of hydro and Class I renewables (wind, solar or energy storage) tried to explain why their projects should be among those selected in January. Contracts awarded under the MA 83D request for proposals are to be submitted in late April. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
The solicitation is a collaborative effort by the Massachusetts Department of Energy Resources and the state’s distribution utilities: Eversource Energy, National Grid and Unitil. DOER Commissioner Judith Judson attended the session, as did Angela M. O’Connor, chair of the Massachusetts Department of Public Utilities, along with 225 others in person and more streaming the event online.
William Hazelip, National Grid vice president of business development, said only his company’s projects meet the key goals set out in the state’s Global Warming Solutions Act of 2008 and the 2016 Act to Promote Energy Diversity, namely to facilitate the financing of new clean energy resources and to minimize “leakage.”
National Grid partnered with Citizens Energy on the Granite State Power Link, an HVDC transmission line from northern Vermont to New Hampshire to deliver 1,200 MW of new wind power from Canada, and the Northeast Renewable Link, a 23-mile AC line from Rensselaer County, N.Y., to Hinsdale, Mass., to deliver 600 MW of new wind, solar and small hydro into the New England grid.
Proposals | National Grid
“The intent of the Diversity Act is clear: It’s about adding new resources to reduce emissions,” Hazelip said. He said leakage — cutting the state’s emissions while increasing them in neighboring regions — would be pronounced with the proposals that rely mostly on existing hydro resources in Quebec.
“Today, the existing hydro is being exported to New York and Ontario,” Hazelip said. “That reduces the use of thermal units and reduces greenhouse gas emissions. Using the Mass. RFP to contract for those resources will only redirect the energy to Massachusetts and raise emissions in New York and Ontario.”
Chris Huskilson, CEO of Nova Scotia-based Emera, made a pitch for his company’s proposed Atlantic Link project, a 375-mile submarine HVDC transmission line extending from New Brunswick to Plymouth, Mass., near the retiring Pilgrim nuclear plant and close to the Boston load center.
“For us, the primary word is ‘diversity.’ [Atlantic Link] provides diversity of supply and allows you to access wind in Maine, wind in the Maritimes, hydro from Newfoundland and potentially hydro from Quebec.”
The project would become operational in December 2022 and deliver 5.69 TWh of clean energy per year to Massachusetts at a fixed price for 20 years.
At 5.7 TWh, Emera’s project would fulfill only half of the RFP, leaving room for another project that can provide supply diversity, Huskilson said.
Atlantic Link Project | Emera Energy
In addition, Atlantic Link terminating “in the southern part of Massachusetts means that it supports the system in the location that really needs that support,” Huskilson said. “The loss of the Pilgrim nuclear plant is going to be something that the system will have to find ways to recover from and the opportunity to connect with this transmission project directly to that location … is a very good opportunity.”
Certainty is Best
Transmission Developers Inc. partnered with Hydro-Québec on the New England Clean Power Link, which includes a submarine cable under Lake Champlain and an overland section to a proposed converter station in Ludlow, Vt., to connect to the existing Coolidge substation. It would bring 1,000 MW of hydropower, solar and wind from Canada.
“The one word for us as we differentiate our project from other projects is ‘certainty’ — on price, on construction, on support, and the certainty of our ability to execute and execute with support, from the governor’s office on down,” TDI CEO Donald Jessome said.
In addition to having all the permits needed for the project, Jessome said TDI also has reserved slots at the manufacturing facilities for production of the cable, which will take a year to produce.
“We know exactly what our project costs and how long it will take and have mapped out every step,” Jessome said. “We know who’s going to be maintaining our project, [Vermont Electric Power Co.] and ABB, once it’s up and running. And of course, we have very good financial backing through the Blackstone Group.”
Focus and Options
Avangrid subsidiary Central Maine Power partnered with Hydro-Québec on the New England Clean Energy Connect, a 145-mile, 320-kV HVDC line that would carry 1,200 MW of hydro and wind energy from Canada to Maine. The company also teamed with NextEra Energy on the Maine Clean Power Connection, a new 345-kV connection from western Maine to the New England grid with capacity options of 460 to 1,110 MW, allowing varying combinations of wind, solar and storage facilities in eastern Canada and far western Maine.
CEO Sara Burns said CMP “focused on the route, focused on the costs and focused on responding with a strong case that we can deliver. … We focused on giving Massachusetts ratepayers a cafeteria plan to choose from.”
Burns said the company is controlling costs by developing lines mostly on a route that the company controls.
“These cost conversations do not have to be too complicated,” Burns said. “If you’re on the route, it drops the prices. We have the route, have the team, have the support.”
Patrick Smith, vice president for transmission business development at Eversource, said the RFP “did specifically contemplate the use of hydroelectric power as qualifying for participation.”
Eversource is partnered with Hydro-Québec on Northern Pass, a 192-mile line to bring 1,090 MW of hydropower to New England — up to 9.4 TWh/year for 20 years starting in December 2020. Hydro-Québec’s proposals with TDI, Eversource and Avangrid all include two proposals each, one pure hydro and one with a wind energy component.
“Has the cost been compared to the current ISO clearing price for power plus transmission, and are these cost savings below that?” asked Steve Cowell, president of E4TheFuture, which advocates for “clean, efficient energy” for residential customers.
“There are additional benefits beyond the clearing price of the energy,” Jessome responded. “There’s the capacity benefit these projects are going to bring to the marketplace. There’s diversity, there’s the fact that you’re now displacing gas during winter peak periods, so you’ve got a gas price benefit. So, you have to look at [it as] a basket. If you look at it in isolation, it’s not as good a story as it is when you look at it terms of the totality of all these benefits.”
AUSTIN, Texas — Appearing before the Gulf Coast Power Association’s Fall Conference last week, Texas Public Utility Commissioner Brandy Marty Marquez was asked about the retirement decisions facing owners of out-of-market coal plants.
“Everyone’s waiting for that shoe to drop,” she responded.
On Friday, the first pair hit the floor when Vistra Energy announced plans to retire three aging coal-fired units in East Texas. The Monticello units date back to the 1970s and have a capacity of 1,880 MW, rendered obsolete by ERCOT’s record low prices.
Vistra CEO Curt Morgan blamed the market’s “unprecedented low power price environment” as having “profoundly impacted” the plant’s operating revenues. He said the market, flooded with cheap renewable energy and low-cost gas generation, “no longer supports continued investment.”
Morgan alluded to the coming retirement announcement when he told the GCPA his company was “assessing the viability of our generation fleet.”
“We are willing to lead in this area, although we believe we are not the only ones who need to undertake some hard decisions,” he said.
Vistra’s decision was not unexpected. Executives told financial analysts in August it was considering retiring some of its coal plants and would make a decision in the fourth quarter. (See Analysts Debate Potential Vistra Coal Retirements.)
Luminant, Vistra’s generation arm, has two other 1970s-era coal-fired plants in Big Brown and Martin Lake. The plants, with 3.7 GW of capacity, have combined capacity factors of 59% and 52%, respectively. Luminant’s 18 GW of capacity includes 8 GW of coal-fired generation and 7.5 GW of gas.
Luminant’s Monticello Power Plant | Luminant
The Monticello units began life as a lignite mine mouth operation, but they switched to Powder River Basin coal in 2016.
Luminant filed a suspension-of-operations notice with ERCOT that triggered a reliability review. If the ISO determines the units are not needed for reliability reasons, Luminant expects to stop plant operations on Jan. 4, 2018.
Vistra estimates it will record one-time charges of approximately $20 million to $25 million in the third quarter of 2017 related to the retirement, including employee-related severance costs. Luminant has estimated the closure will affect about 200 employees.
ERCOT has also received suspension notifications for three smaller gas-fired units.
The City of Garland told ERCOT on Oct. 2 it plans to indefinitely suspend operations of two of its Spencer plant’s units, totaling 118 MW of capacity, in January. The units went into service in 1966 and 1973.
On Sept. 27, Talen Energy said it plans to retire a 330-MW gas unit at its Barney Davis plant near Corpus Christi in December. The unit went into service in 1974.
ARLINGTON, Va. — The panels at the Organization of PJM States Inc.’s annual meeting last week took on a wide variety of topics, but two themes rose to the top: cheap natural gas from local shale deposits has undoubtedly upended the electricity industry; and no matter how pure a market is, nothing will prevent the taint of politics.
“Politics sort of have everything to do right now in the energy market space,” said Susan Bruce, who represents the PJM Industrial Customers Coalition. “Low natural gas prices may have an adverse effect on certain PJM market participants, but as a general matter, the shale gas revolution should be viewed as a real positive for our region. Businesses make decisions to site here because of that. If we mute that in some fashion to give competitive advantage to others, I think we, looking at the issues as a whole, have done ourselves a disservice from an economic perspective.”
State regulators agreed. In the meeting’s opening panel, regulators of several PJM states tracked the current debate over providing subsidies to nuclear units — most notably through Illinois’ zero-emissions credit program — back to the low gas prices suppressing auction results so that “generation owners are not making enough money in the marketplace,” said Asim Haque, chair of the Public Utilities Commission of Ohio.
“If the power markets are just going to now be about state and federal politics, I think we’ve got a problem,” Haque said. “I worry where our collective heads are at. I worry that we’re all going to continue to be entrenched in our state policy and political objectives. … I do have fears of a full-on accommodation of all state subsidies.”
Pennsylvania Public Utility Commission Chair Gladys Brown noted her commission traditionally protests efforts to introduce unit-specific subsidies. The Pennsylvania legislature has developed a large pro-nuclear caucus and held two hearings on developing financial support for the state’s nine nuclear units, she said, but “we as a commission still have not been called over to provide any type of testimony.”
“It’s a catch-22 because we want access to that cheap natural gas, but they also know we’re a diverse state and we have so many other things that we could offer in terms of generation,” she said.
Illinois Commerce Commissioner John Rosales said he was “proud” of his state’s ability to coalesce around the issue and decide to support nuclear generators. “It was the right decision,” he said. “I realize there’s always going to be some political attributes that come into play.”
Kentucky Public Service Commissioner Talina Mathews noted that her state “loves to say how different it is” as one of the few in PJM that is fully regulated, has no renewable energy portfolio, energy efficiency standards or carbon emission goals, and remains a staunch advocate for coal use.
Still, she joined other regulators in defending states’ abilities to make decisions for their residents.
Differing Priorities
When asked what changes to the capacity market they endorse, only New Jersey Board of Public Utilities President Richard Mroz would say he favors a redesign that supports nuclear, saying “there are other attributes that are not being valued that should be valued.”
“I do not know who to trust anymore,” he said. “On the state side, you’ve just got different priorities developing. You’ve got different priorities developing in different states,” he said. “This is the sort of implicit cooperation that’s supposed to exist between the states when we’re all in this marketplace together, and Ohio unequivocally — when we made our [power purchase agreement] decisions [to subsidize some in-state generation units] — was a violator of that implicit cooperation.”
He said that Ohio is taking a different position now.
“The decision that I made when I was sworn in as the chair in 2016 was that the PUCO was out of the generation business,” he said. “Our advocacy now going forward will very much be tailored around trying to be constructive with that cooperation the best we can until we get to a breaking point where I think I’ve got to protect Ohioans. … We will start to become very active if I think that my residents and my businesses are going to be asked to stand on the Titanic.”
In a lunchtime address, PJM CEO Andy Ott explained that gas-fired units used to be on the margins of receiving enough revenue to cover their costs. However, they were small and flexible enough to turn on and off quickly as prices dictated. Cheap gas has allowed those units to offer into the market so low that they can always run and don’t have to respond to price signals. That has pushed large, inflexible units to the margin, where they can’t respond to price changes quickly, or at all. So that attribute of flexibility, which was previously inherent to the system, now needs to be valued in the market, he said.
“Hopefully, we’re not trying to solve a political problem,” he said.
Kathleen Barron, Exelon’s senior vice president for government and regulatory affairs, said markets are adjusting to state preferences. Her comments seemed to echo those made by James Wilson of Wilson Energy Economics, who consults for several state commissions and has argued at PJM stakeholder meetings that markets can absorb state actions given enough time and information. Tonja Wicks, who oversees FERC and RTO affairs for Duquesne Light, said her company has concluded the existing capacity design is the right one for now.
It wasn’t a surprise that Barron supported her own company’s proposed revisions, but she acknowledged, “I think we have a ways to go to make sure that what we actually adopt is fair to customers.”
Part of that may be because “we’re talking about different kinds of subsidies” that forestall exit from the market rather than incentivize entry as other state policies have done, said Marji Philips, Direct Energy’s director of RTO and federal services. They’re also targeted at a few very large units rather than many smaller ones.
“It’s about politics, and it’s really hard to price politics,” Philips said.
“What it really gets down to is investor confidence,” said Steve Schleimer, Calpine’s senior vice president for government and regulatory affairs.
There are trusted ways to secure a return on investments in competitive and regulated environments, but “where it’s part-competitive and part-regulated … that’s not stable.”
Split Over Cost Containment
In a separate session, stakeholders split on whether to factor cost-containment guarantees into proposals for transmission development.
PJM’s Craig Glazer said the RTO could consider caps on construction costs but isn’t prepared to determine whether other guarantees are suitable. He said PJM should “stay in our lane,” and Gloria Godson, vice president of federal and PJM policy for Exelon’s Pepco Holdings Inc., agreed.
However, Sharon Segner, vice president of power development for LS Power, disagreed.
“We have a lot of reservations about that policy. If PJM is going to take [the opposite perspective of] every other RTO on cost containment, that’s a discussion that should go on with FERC,” she said.
She and West Virginia Consumer Advocate Director Jackie Roberts said they were willing to pay extra to develop a “robust” independently administered evaluation process. Roberts suggested a plan in which proposals would be requested during a certain time frame and submitted using the same form so they could create “an apples-to-apples” comparison. The current system allows developers to submit proposals in any form they wish.
“If my money’s being spent, I want to know that the most creative solution is being proposed and that everybody is on a level playing field to fix that solution. This is what all businesses do, and the fact that it has not come to transmission planning is because PJM has been trying very hard to fix its time constraints,” Roberts said. “You just don’t have time for that, but others do. … I’m convinced that consumers will be better served by a real bid process that puts the risk of the business on the people making the bids, who are the people who know what the risks are and should bear them. That’s something that I’m willing to get my checkbook out for.”
