FERC last week rejected a request by several SPP members that they be exempted from congestion and marginal loss charges under a grandfathered contract signed before they joined the RTO (ER14-2850-008, ER14-2851-008).
The commission ruled Sept. 26 that Missouri River Energy Services, Basin Electric Power Cooperative, Western Area Power Administration – Upper Great Plains (Western-UGP), Heartland Consumers Power District and Nebraska Public Power District (NPPD) were ineligible for “carve-out treatment” under the SPP Tariff and a 1977 transmission service contract between NPPD and Basin Electric.
The 1977 contract arose from construction of NPPD transmission needed to deliver power to Western-UGP and Lincoln Electric System from the Missouri Basin Power Project — a venture owned by six public power and cooperative utilities that includes the 1,710-MW Laramie River coal generator, the Grayrocks Dam and reservoir, and more than 500 miles of EHV transmission.
Laramie River Station | Burns & McDonnell
The commission ruled that the utilities were not eligible for a carve-out, although it acknowledged that the section of the SPP Tariff governing grandfathered agreements (GFAs) was “ambiguous.”
The commission rejected the utilities’ claim that they should be exempted from the charges because FERC had previously granted carve-out status to Lincoln, which was also a party to the 1977 contract.
“Though parties to the same contract, Lincoln Electric and [the] parties seeking carve-out treatment are in a fundamentally different position with regard to the costs of participating in SPP because of when each party chose to join SPP,” the commission said. “Lincoln Electric, an SPP member since 2008, was subject to a forced transition to a day-two energy market when SPP adopted the Integrated Marketplace in 2014 and, therefore, received carve-out treatment along with several other non-jurisdictional GFAs that were also subject to a forced transition. On the other hand, [the] parties seeking carve-out treatment were not subject to a forced transition to a day-two energy market when they joined SPP after the commencement of the Integrated Marketplace. Parties seeking carve-out treatment had a choice of whether or not to subject themselves to SPP’s market rules.”
Network Agreements Approved
In a separate order Sept. 25, the commission approved SPP’s unexecuted network integration transmission service agreements with Kansas Power Pool (KPP) effective June 1, 2017, and its executed network operating agreements with KPP, Midwest Energy Inc., Mid-Kansas Electric Co. and Westar Energy effective Sept. 1, 2017 (ER17-2032-002, ER17-2038-002).
KPP protested the service agreements’ inclusion of language describing KPP’s potential liability for credit payment obligations. KPP said that SPP staff had informed it that transmission studies had indicated it would not be responsible for any credit payments because they would be fully covered by base plan funding.
The commission rejected KPP’s complaint, saying the company could be liable for credit payments because final cost information is not available for one upgrade under the agreements, the Woodward EHV 138-kV phase shifting transformer circuit #1.
“When SPP receives the final cost information for the Woodward upgrade, SPP can determine whether all the credit payment obligations are fully covered by base plan funding,” the commission said.
Last week saw a handful of CAISO-related developments at FERC, including the commission’s suspension of a Pacific Gas and Electric transmission rate request and approval of Portland General Electric (PGE)’s authority to charge market-based rates in the Western Energy Imbalance Market (EIM) ahead of the utility’s Oct. 1 entry into the market.
The commission on Thursday set settlement hearings over PG&E’s request for a transmission rate increase after receiving protests from state regulators and others. FERC accepted and suspended until March 1, 2018, PG&E’s request for a 6% increase, saying there are issues that “are more appropriately addressed through hearing and settlement judge procedures” (ER17-2154).
In its July 27 tariff filing, the utility said the rate increase will allow it to recover costs incurred so far in 2017 for transmission expansion, as well as in 2018. It expects to invest $1.2 billion this year and another $1.4 billion next year. The approved rates would produce about $1.8 billion in revenue in 2018.
PG&E said the requested increase is largely driven by the need to replace aging infrastructure. Other factors include compliance with reliability rules and the magnitude and location of changes in California’s forecasted electricity load. A substantial amount of its system was built more than 50 years ago, PG&E said.
Numerous protests were filed by parties, including the California Public Utilities Commission, a handful of California cities, the Energy Producers and Users Coalition, municipal electric agencies and the Transmission Agency of Northern California.
Some protesters argued that PG&E’s proposed 10.25% return on equity should be no higher than 8.84%, and there were disputes over the proxy group screening tool, which is used to determine a reasonable return. Others disputed the utility’s request for a 50-basis-point adder for participation in CAISO, which FERC granted.
The PUC’s challenge of two recent FERC approvals of the adder in previous tariff filings are on appeal with the 9th U.S. Circuit Court of Appeals. FERC rejected the PUC’s request to abstain from a ruling on the current adder until that court proceeding is resolved.
ISO Submits Aliso Canyon Measures
CAISO also submitted Tariff amendments to address the loss of the Aliso Canyon natural gas storage facility. The measures extend previously approved changes that can limit market bidding flexibility in response to gas constraints.
“The maximum gas constraint has proven to be a useful and discrete tool that balancing authority areas can use to reflect the interactions of gas limitations in the electric market optimization. Therefore, the CAISO proposes to adopt that measure on a permanent basis and throughout its entire system,” CAISO said.
The measures allow the grid operator to constrain the operations of gas plants across the state and the EIM, part of a package of initiatives drawn up in response to the loss of the storage facility after a massive leak was discovered in October 2015. The proposal required approval by the CAISO Board of Governors and the EIM Governing Body. (See CAISO Board Approves Aliso Canyon Rules Package.)
Portland General Electric Begins EIM Participation
FERC also approved PGE’s application to charge market-based rates in the EIM, saying that the Oregon utility’s balancing authority area will not be a sub-market and does not require a separate market power analysis (ER17-1693).
PGE began transacting in the EIM on Oct. 1. The company in early September briefed the EIM Governing Body on its implementation activities. It reached an implementation agreement with CAISO in November 2015.
“We could never have imagined in ’27, or even in 1997, what we’d grow into,” Ott said. Yet, he added, “Our mission remains the same: to keep the lights on.”
Senior executives of the three utilities that founded PJM — Exelon’s PECO Energy (formerly Philadelphia Electric Co.), PPL and Public Service Electric and Gas — were among more than 100 in attendance.
“Today, PJM represents the largest energy-transaction marketplace in the world,” said Exelon Utilities CEO Denis O’Brien, noting that his company now owns almost half of the dozen companies that were PJM members when he began his career 35 years ago. He presented Ott with a photograph of the lighted signs at the top of PECO’s landmark building in Philadelphia displaying a message of congratulations to PJM.
PPL CEO William Spence congratulated the many people who transformed PJM into the world’s first continuing power pool.
“Today, nearly a century after PJM’s founding, it’s hard to imagine life without the electricity that we provide,” he said, noting its importance to medicine, education and the economy. “It was these people who transformed that 1920s patchwork of power lines and power plants into the robust interconnected system that we have today.”
Ralph Izzo, CEO of PSE&G parent Public Service Enterprise Group, noted that PJM was originally named PNJ, but changed its name as it expanded. The idea for the interconnection came when a company engineer realized that if every electrical device was turned out simultaneously, it would demand 3.5 times more power than the company owned, Izzo said. Only through “a fortunate lack of coincidence … this nightmare never materialized,” Izzo said.
The power pool allowed resources that were going unused in one company’s territory to be used in another area where demand was outstripping supply. “At the outset, transmission was the great enabler of the founders’ vision,” Izzo said.
The mood at the celebration was light, and many speakers found opportunities for humor.
PJM has “lasted through the Great Depression, through war and economic troubles, through FERC Order 1000,” Izzo joked. “Oh, that wasn’t in the script.”
Commissioner Robert Powelson came to FERC’s defense.
“I think it’s fair to say that if Thomas Edison were here today he would say, ‘Job well done, Andy and team,’” he said. “And he would say, ‘Job well done, Federal Energy Regulatory Commission.’”
Powelson, a former member and chair of the Pennsylvania Public Utility Commission, also singled out Mike Bryson, PJM’s vice president of operations, for “doing the boring good” to ensure the reliability of the RTO’s $30 billion in annual electron sales.
“Not a lot of people know who you are; I know who you are,” he said. The PJM staff “make Federal Energy Regulatory Commission commissioners look good in spite of ourselves.”
Current PUC Chair Gladys Brown noted that PJM is 10 years older than her commission. She thanked the RTO for being the “backbone” of wholesale energy transactions that enables her state’s competitive retail sales program.
She also voiced appreciation for the “tightrope and tug-of-war” that PJM staff administer in the stakeholder process, referencing the current efforts to accommodate state generation subsidies without allowing them to impact competitive prices. (See related story, PJM Pressed on Plans to File Capacity Changes.)
Pennsylvania is “proud” to be PJM’s home and birthplace, she said.
Richard Mroz, president of the New Jersey Board of Public Utilities, brought congratulations from a long list of industry stakeholders, including the National Association of Regulatory Utility Commissioners.
U.S. Rep. Ryan Costello, who represents the district that is home to PJM headquarters, said “a secure, safe, reliable, efficient grid is critical for the future of our country.”
“It is a particular source of pride for me when we have a power subcommittee roundtable and we’re talking about the challenges facing RTOs moving forward, and who’s really running the show? Who does everybody listen to?” he said. “It’s the folks at PJM, because you are out front in terms of innovation, and you are out front in terms of wrestling with the complexities and the challenges that RTOs face.”
MISO planners continue to sift through the largest batch of interconnection applications in a decade while still working out lingering details about the RTO’s new queue process.
In the last year the queue has grown to 355 projects totaling 58.8 GW.
| MISO
“I don’t think we’ve ever had 191 projects enter the definitive planning phase at once,” said MISO planning manager Neil Shah, speaking about the August 2017 cycle of projects, representing 32 GW. The RTO accepts new projects into its queue twice per year, in August and February.
Stakeholders participating in a Sept. 26 Interconnection Process Task Force (IPTF) conference call asked if all the proposed projects will complete the queue’s studies.
“From MISO’s perspective, they’ve submitted everything they’ve needed under the Tariff,” Shah said.
“There’s a lot of capacity in the queue, and a lot of it won’t come online, but a lot of it will,” CEO John Bear said during a Sept. 21 board meeting, adding that solar and renewables represent a large share of prospective projects. At the same meeting, Executive Vice President of Operations Clair Moeller noted that the queue hasn’t been so packed since 2007.
Amid the heavy queue workload, stakeholders must also decide whether to continue the IPTF under its current structure, or convert it into a working group to finish implementation of the new queue design, which is intended to streamline a process beset by restudies and backlogs. However, MISO staff have already warned stakeholders to prepare for delays as the approximately 100-employee queue team examines the copious amount of projects.
Rhonda Peters, a Wind on the Wires consultant, urged IPTF leadership to consider the switch to a working group.
| MISO
“We have a lot of needs with this interconnection queue, and they’re not going away. They’re urgent needs. … We need to not waste time discussing a sunset date every six months,” Peters said.
Wisconsin Public Service’s Chris Plante said he was also in favor of moving to a more permanent working group organization, noting that he’s saved documents from 2008 IPTF meetings.
“We’re pushing 10 years here, and from a Stakeholder Governance Guide standpoint, that’s not temporary,” Plante said.
Vikram Godbole, MISO director of resource utilization, said the larger goal was that stakeholders continue working out a new queue process, whatever the venue. IPTF Chair Randy Oye asked for stakeholder comments on whether they support discussing interconnection issues under a working group or task force structure.
MISO attorney Jacob Krause also said the RTO is seeking written stakeholder feedback on the number of days that should be allowed for negotiating and executing generator interconnection agreements.
In early September, FERC ruled that MISO did not provide “sufficient support” for Tariff revisions that would have required that generator interconnection agreements be negotiated and executed within 90 days, down from the current 150 days. (See FERC Blocks MISO Plan to Shorten Queue Negotiations.)
Oye said he didn’t see why the RTO couldn’t shorten the agreement timeline by having interconnection customers and transmission owners simultaneously sign off on agreements. Currently, agreements are negotiated for 60 days, with customers given additional 60 days to execute the agreement. TOs then have another 30 days to sign off.
MISO staff asked for written comments so the issue could be taken up again in October.
MISO is seeking stakeholder guidance on how to forecast the probable locations of future renewable, energy storage and distributed energy resources in order to better inform its transmission planning.
To prepare for MISO’s 2019 Transmission Expansion Plan modeling, stakeholders had asked the RTO to update probable utility-scale renewable zones, map out future storage placement based on likely economic benefits, create an electric vehicle siting methodology and gather more information on DER through forecasts of customer-driven adoption and surveys of load-serving entities.
“Some of these categories are relatively new to our MTEP process,” MISO Senior Policy Studies Engineer Jordan Bakke said.
James Okullo with MISO’s policy studies group said MTEP 19’s utility-scale renewable study, prepared by Vibrant Clean Energy and used to predict future renewable siting, may include areas outside of the RTO’s territory.
“We cannot ignore the impact of our neighbors and what’s happening outside of our footprint,” Okullo said during a Sept. 29 MTEP 19 workshop.
The RTO’s current MTEP siting methodology allows for siting of about 50 GW of new wind projects and 9 GW of utility-scale solar expansion in the footprint over the next 15 years.
Okullo said MISO would also examine which states have opened state-owned land to renewable project siting.
ITC Holdings’ Cynthia Crane asked if the RTO would want utilities and states to supply information on county efforts to stifle renewable siting, pointing to residents in Michigan’s Thumb region that are actively campaigning against new wind farms.
Okullo said such information would be useful to MISO planners.
After stakeholders suggested the RTO rank its states in order of receptivity to renewable development, Indiana Utility Regulatory Commission adviser Dave Johnston cautioned against such a political exercise.
“In a state like mine, you wouldn’t think we’d be very open to renewable development, but we’re very into economic development and manufacturing, so we welcome those plants. So it’s hard to paint states in certain boxes. It’s hard to predict,” he said.
In MTEP 18, MISO projected the siting of 2 GW of future energy storage in its future with the most aggressive growth of DER. It also placed no more than 100 MW of energy storage at any single load bus in the next 15 years. In MTEP 19, MISO could predict greater penetration by studying the full range of storage benefits, engineer Kunjal Yagnik said.
Wind on the Wires’ Natalie McIntire asked why MISO would include energy storage in MTEP resource assumptions when storage could very well solve transmission needs and become a project recommendation itself.
“It seems like it could serve both functions,” she said. MISO officials agreed.
Bakke said MISO will have to sort through the several nuanced benefits of storage when predicting future locations. For example, storage could be placed near a proliferation of renewable resources or situated in areas where frequency response could use improvement, he said. Customized Energy Solutions’ David Sapper said he agreed with MISO’s view of storage as a “composite resource.”
Ann Benson, a MISO policy adviser, said the RTO is looking for better ways to increase DER visibility in MTEP siting. She asked stakeholders for ideas about how MISO could prepare a more complete database of existing and anticipated DER locations.
Marcus Hawkins, director of member services for the Organization of MISO States, advised MISO against using footprint-wide assumptions for DER trends, noting that in listening to recent discussion from stakeholders and regulators, he’s heard a clear preference for a state-by-state differentiation of DER assumptions.
If appropriate, MISO could also forecast use of other emerging technologies, MISO policy studies staffer Temujin Roach said. Those could include small hydropower resources near rivers and lakes, small modular nuclear reactors and compressed air energy storage.
MISO will hold two more workshops before moving forward with final MTEP modeling in early 2018. For now, the RTO is asking stakeholders by Nov. 1 to provide suggestions on how to incorporate forecasts for renewable and new technologies into MTEP modeling and resource siting.
RENSSELAER, N.Y. — NYISO will soon announce the formation of a carbon pricing task force, CEO Brad Jones told the Management Committee on Wednesday.
The task force will “provide guidance on implementation, to explore how fast we can move forward on these issues,” Jones said.
NYISO in August released a Brattle Group report on pricing carbon into its wholesale energy market to support New York’s decarbonization goals. At a Sept. 6 public hearing held by the ISO and the New York Department of Public Service, stakeholders offered broad support for incorporating a $40/ton carbon charge into the market. (See NYISO Stakeholders Talk Details of Carbon Charge.)
Stakeholders are still concerned about how the costs for decarbonization will be allocated, and committee participants wondered who would be running the task force. Jones said the group will report to the grid operator’s Market Issues Working Group.
Hot September Causes Historic First in Flow Limits
Unseasonably warm weather in the second half of September led NYISO to secure the West Central interface to limit flows toward western New York, the first time the ISO had to secure flows in the reverse direction because of high levels of Lake Erie loop flows, COO Rick Gonzales said.
Western New York transmission | NYISO
“This shoulder period is usually the time for generators and transmission owners to schedule their off-peak maintenance outages, so unusually warm weather during this period can present reliability challenges,” Gonzales said. “We did reschedule a number of major transmission maintenance outages to later in the week and bring on one additional generator to make sure that NYISO was meeting its reliability commitments.”
In his regular operations report, Gonzales highlighted that “peak load in August was even less than the peak load in July, so we didn’t even reach 30,000 MW of peak load this summer.” The balance of the operations report was delivered at the Business Issues Committee earlier in September. (See NYISO Business Issues Committee Briefs: Sept. 12, 2017.)
Mild Summer Poses Few Challenges
This summer was the fourth consecutive summer in which the ISO’s peak load fell short of the 50/50 forecast, Vice President for Operations Wes Yeomans said.
The Summer 2017 Hot Weather Operations report showed that actual ambient temperatures, total summer loads and peaks were all below 50/50 projections. New York did experience two instances of hot weather, but only for short durations.
| NYISO
A warm front crossed Upstate New York and New York City during June 11-13, with Albany registering temperatures of 95 F and LaGuardia Airport hitting 100 F. June 13 peak load was 29,126 MW.
NYISO’s summer peak of 29,699 MW occurred July 19, coming in far below the 50/50 peak forecast of 33,178 MW, Yeomans said. NYISO met all reliability operating criteria during the peak and required no statewide out-of-market commitments or demand response activations, he said.
Yeomans noted that New York State Electric and Gas this summer completed its Auburn Transmission Project, which included construction of a new 115-kV Elbridge-State Street line and re-conductoring of the existing line linking those points. The upgrades provide higher thermal ratings and alleviate the need for the coal-fired Cayuga plant to maintain local reliability.
A new 345-kV Dolson Avenue substation interconnection for the CPV Valley Energy Center was completed in early September and the second Ramapo phase angle regulator returned to service Sept. 14, Yeomans said.
2018 Budget up 5% on Security Enhancements
NYISO’s draft 2018 budget calls for $155.7 million in spending allocated across a forecast of 157.8 million MWh of usage, representing a Rate Schedule 1 charge of 98.7 cents/MWh, according to an overview presented by Alan Ackerman, chair of the Budget and Priorities Working Group.
The draft budget represents a 5% increase in revenue requirement from this year and a 0.3% decrease in projected megawatt-hours, translating into a 5.45% increase in transmission charges.
Among the ISO’s key priorities for next year are physical and cybersecurity enhancements to secure operations and meet audit and compliance needs. System and resource planning will focus on reliability and the support of studies requested by the Public Service Commission, including assessing potential public policy transmission needs such as offshore wind integration, Clean Energy Standard implementation and congestion in the North Country (the state’s extreme northern frontier, bordering Lake Ontario, Lake Champlain, the Saint Lawrence River, Vermont, Ontario and Quebec).
Busy NYISO Agenda Drives Consumer Impact Analysis
The ISO will conduct consumer impact analyses on five major projects for 2018, NYISO Senior Manager for Consumer Interest Liaison Tariq N. Niazi told the committee. The ISO conducts such analyses for projects with anticipated net production cost impacts of at least $5 million or changes in energy or capacity market prices of at least $50 million per year.
Also to be analyzed are projects incorporating new technology into ISO markets for the first time, those that allow or encourage a new market product and those that create mechanisms for out-of-market reliability payments. The grid operator leaves room in the process for unanticipated analyses, such as FERC directives where NYISO has implementation flexibility or emergent stakeholder issues.
For 2018 the projects being analyzed are:
Integrating Public Policy: This project is attempting to accommodate state’s decarbonization goals with the wholesale energy and capacity markets and align the process with the Reforming the Energy Vision initiative.
Buyer-Side Mitigation (BSM) of Repowering Projects: To encourage private investment, the ISO will seek to develop a specially tailored BSM evaluation process that reduces the potential for over-mitigation of repowering projects.
Constraint Specific Transmission Demand Curves: The ISO will would study replacing its current transmission constraint pricing methodology with multiple transmission demand curves that can vary according to the importance, severity and/or duration of the transmission constraint violation. It would replace the current procedures, in which some transmission shortages are resolved by relaxation instead of by setting prices through use of a transmission demand curve. The goal is more efficient pricing of transmission constraints, reduced price volatility and more efficient resource scheduling.
DER Participation Model: The ISO is evaluating potential modifications to its existing demand response programs as part of the Distributed Energy Resource (DER) Roadmap it announced in February. (See NYISO ‘Roadmap’ Sees Dispatchable DER by 2021.) The project will include the design of DER performance obligations, metering and telemetry requirements, baseline and performance measurement and verification rules, and resource modeling. It also will seek to develop ways to balance the simultaneous participation of DER in the wholesale markets and retail-level programs.
Energy Storage Integration and Optimization: The ISO will continue to develop its model for the participation of energy storage in the wholesale markets, including improving the optimization of storage on a least-cost basis through more sophisticated energy constraint modeling. The goal is to improve modeling of resources that can inject and withdraw energy from the grid in response to ISO dispatch signals.
MC Approves Western New York Tx Proposal
The Management Committee voted unanimously to advise the Board of Directors to approve NextEra Energy’s proposed Empire State Line in western New York, as recommended by an ISO public policy transmission planning report. The ISO’s Business Issues Committee endorsed the same report earlier in September. (See Public Policy Tx Project Wins Key NYISO Endorsement.)
Dawei Fan, NYISO supervisor of public policy and interregional planning, presented the report, which represents NYISO’s first-ever evaluation of transmission needs stemming from public policy requirements.
NYISO received comments on the report from the New York Power Authority, NYSEG, New York State Energy Research and Development Authority, NextEra and LS Power’s North America Transmission, the last of which intends to pitch its own transmission project to the board on Oct. 16, before the board’s October meeting.
Several meeting participants sought more information about what topics would be discussed at the upcoming board meeting and whether their absence would “dilute” the impact of their already submitted comments. Howard Fromer of PSEG Power wanted to know if participants seeking to speak to the board planned to address legal arguments as opposed to more technical points.
NYISO Vice President for System and Resource Planning Zachary Smith responded that the comments would not focus on legal matters and asked that all supplementary comments be delivered to the RTO by Sept. 29. Stakeholders who want to speak directly to the board were asked to notify the RTO by Oct. 3.
Remember the Cash for Clunkers program? Inefficient cars paid to go away.
The Energy Department’s directive to FERC last week is Cash for Clunkers with a twist: inefficient generators paid to stay.
The original Cash for Clunkers was an economic stimulus for new stuff to replace the old stuff. The DOE’s Notice of Proposed Rulemaking subsidizes the old stuff to stop the new stuff: a sort of stimulus in reverse. (See related story, Perry Orders FERC Rescue of Nukes, Coal.)
So we might say the DOE version is a Twisted Sister sort of twist on the original.
Bailing out the Retiring, Retired and Canceled Clunkers, and then Everyone Else
We know with certainty that the DOE proposal subsidizes the inefficient because those are the plants that will opt for the federal rate guarantee instead of market-based rates. How will this play out?
DOE says there are 34 GW in projected retirements over the next five years. Under the DOE proposal, none of that would retire and instead would go on the federal dole.
And then there’s the 71 GW that already retired over the last six years but will likely return, like “Night of the Living Dead,” for that federal rate guarantee.[1]
And how about all those canceled nuclear projects?
So we’ll have around 100+ GW of uneconomic clunkers crashing the markets, and of course crashing market prices. This will force all the economic plants that depend on legitimate market prices to join the federal dole.
Natural gas plants will do this by simply adding 90 days’ worth of oil tanks.[2]
What will all this cost consumers? DOE doesn’t even try to answer that question, but here’s one way of looking at it. First, we can assume that FERC won’t want thousands of individual rate cases for all the power plants in all the RTOs.[3]
So FERC would need some sort of standard compensation. Let’s say it adopts a cost of new generation, maybe $400/MW-day.[4] Generation in the RTOs is around 530 GW; add the roughly 70 GW of retired clunkers that will return from the dead for about 600 GW on the federal dole. That’s about $88 billion annually.
So we are talking about tens of billions of dollars a year squandered first on what are, by definition, uneconomic resources, and then by paying economic resources that are rendered uneconomic by the clunkers and forced onto the same federal dole.
I can’t help noting how Republicans blasted the original Cash for Clunkers,[5] which had a one-time cost of $3 billion. The DOE version is tens of billions of dollars every year, forever.
Resiliency
DOE says that its proposal is about “resiliency” (the new buzzword for reliability). But the retiring plants really are clunkers, as this PJM slide excerpt illustrates (I’ll translate the jargon after the slide):[6]
| PJM
The deactivating (retiring) stuff has an outage rate — equivalent forced outage rate-demand (EFORd) — that is three times the new stuff (14.56% versus 4.42%). Yet DOE wants to subsidize these clunkers so they won’t retire.
And that somehow is going to improve resiliency, again in a Twisted Sister sort of way.
90 Days of Fuel Supply on Site
A few words about the fuel supply requirement. DOE relies heavily on PJM’s experience in the polar vortex of 2014 and claims that natural gas supply was the major problem. It was not. As this PJM chart plainly shows, natural gas interruptions affected 9,300 MW, accounting for less than 25% of total forced outages of 40,200 MW:[7]
| PJM
The FERC testimony of Mike Kormos, PJM’s executive vice president at the time, directly contradicts DOE’s main claim: “Natural gas interruptions removed less than 5% of the total capacity required to meet demand on Jan. 7, [2014], while equipment issues associated with both coal and natural gas units made up the far greater proportion of forced outages.”[8] (Emphasis added.)
Beyond equipment issues, another basic flaw in a metric like fuel supply on site is that coal piles freeze, as some did in the polar vortex. Years of coal supply on site would be worthless if frozen. And of course, nuclear plants can’t run during refueling and other outages. Years of nuclear fuel on site would be worthless during those outages.
Here’s a fun fact you won’t find in the DOE NOPR: Baseload (combined cycle) natural gas plants average lower forced outage rates (4.29%) than baseload coal plants (7.71%), and have about the same as nuclear plants (3.51%).[9] It’s these overall forced outage rates that matter — not a single metric like fuel supply on site.
As for 90 days specifically, DOE provides zero rationale for that. In the polar vortex, the generation emergencies in PJM aggregated 20 hours.[10] What is magic about 90 days (other than being tailored to the average coal plant stockpile)?
FERC and RTOs like PJM have learned from the polar vortex to reward performance and penalize nonperformance, instead of using a meaningless metric like days of fuel supply on site.
PJM hasn’t had a single system generation emergency in more than three years — that’s more than 26,280 hours of reliable operation. And PJM locks down adequate, reliable generation resources years in advance.
Bottom line: DOE proposes to take a system that is incredibly reliable and squander tens of billions of dollars on uneconomic resources to make it less reliable.
J&R Gone Missing
Absent from the DOE NOPR is an explanation of how its proposal would satisfy the lodestar requirement of the Federal Power Act that all rates be just and reasonable.[11]
Subsidizing uneconomic clunkers in organized markets is the antithesis of just and reasonable rates. It would be a repudiation of everything that FERC has sought to accomplish over the last 25 years.
Maybe Rick Perry was right all along: DOE should be abolished.
If you’re one of those owners, you might want to hold the wrecking ball. Or come to think of it, maybe you wouldn’t: more rate base if you wreck and rebuild. ↑
The Wall Street Journal cites unidentified experts for the notion that only nuclear and coal plants will qualify under the DOE proposal. That is wrong. Installing oil storage at natural gas plants is routinely done. Of course, if rate base becomes the game, LNG tanks would be used instead. ↑
There’s a straight-faced argument for that: If new generation investment costs that much, existing generation should be compensated at the same level. Otherwise we would be incenting existing generation to retire that would cost less to keep around than paying for replacement new generation. ↑
DOE gives lip service to the statutory requirement by using the term “just and reasonable” twice in its proposed regulation. It’s like saying “bring me a blue rock that is red.” ↑
Western utility PacifiCorp is seeking bids for up to 1,270 MW of wind power to integrate into its system by the end of 2020.
Successful proposals for new or repowered wind projects must demonstrate that they qualify for the federal production tax credit and can achieve commercial operation by Dec. 31, 2020, according to the company’s request for proposals.
The RFP is for “new or repowered wind energy interconnecting with or delivering to PacifiCorp’s Wyoming system with the use of third-party firm transmission service and any additional wind energy located outside of Wyoming capable of delivering energy to PacifiCorp’s transmission system that will reduce system costs and provide net benefits for customers.” The minimum project size is 10 MW.
Benchmark bids for PacifiCorp’s RPF are due on October 10. | PacifiCorp
Portland, Ore.-based PacifiCorp said it would consider a “build-transfer” agreement where the developer assumes responsibility for construction and transfers the facility to PacifiCorp, or a power purchase agreement for up to a 30-year term.
“These new wind resources are a key part of the company’s plan to both meet customer energy needs and continue our cost-conscious transition to less carbon-intensive energy,” said Stefan Bird, CEO of PacifiCorp’s Pacific Power unit.
PacifiCorp will hold a bidder conference on Oct. 2, with notices of intent to bid due Oct. 9 and benchmark bids due by Oct. 10. RFPs for Wyoming-based projects are due on Oct. 17 and non-Wyoming projects on Oct. 24. Agreements will be executed by April 16, 2018, according to PacifiCorp’s schedule. The RFP requires approval from Utah and Oregon regulators.
PacifiCorp included in its 2017 integrated resource plan a proposal to add new wind resources. (See PacifiCorp IRP Sees More Renewables, Less Coal.) The wind energy will be procured in association with the new 500-kV Aeolus-Bridger/Anticline transmission line, a segment of PacifiCorp’s Energy Gateway, a 2,000-mile transmission project that has been developed over the past 10 years. The wind solicitation is part of the IRP’s “Energy Vision 2020” initiative, which also includes plans to repower and improve the utility’s current wind portfolio.
PacifiCorp is a subsidiary of Berkshire Hathaway Energy and serves 1.8 million customers in six states through its Pacific Power and Rocky Mountain Power subsidiaries. PacifiCorp operates 72 generating units with nearly 11,000 MW of capacity, which is currently 62% coal, 15% natural gas, 7% wind and 5% hydro, and the rest coming from biomass, solar, nuclear and geothermal.
Entergy on Thursday said it will continue to operate the Palisades nuclear plant until early 2022 under the terms of its original agreement with Consumers Energy, representing an about-face for the companies after they announced last winter they planned to terminate the arrangement.
The two companies now say they will honor the terms of their 15-year power purchase agreement, which will keep the Michigan nuclear unit running until April 2022. The companies signed the deal in 2007 after Entergy paid Consumers parent CMS Energy $380 million for the plant.
Palisades plant | Entergy
Charlie Arnone, Entergy’s top official at Palisades, said last week’s ruling from the Michigan Public Service Commission factored heavily into the decision to terminate the buyout of the PPA. The Sept. 22 order (U-18250) permitted Consumers to issue securitization bonds for just $142 million of the $184.6 million in qualified costs needed to buy out the PPA. Consumers planned to make a one-time, $172 million payment to Entergy.
The PSC said Consumers’ substitute capacity plan was not solid enough to grant the requested funds, and customer savings as a result of exiting the PPA wouldn’t be as significant as the company had estimated.
“Having certainty around the replacement portfolio is integral to the commission’s determination on whether a regulatory asset should be granted because it will ultimately affect electric reliability and whether savings will be achieved,” the PSC wrote in its decision. “Accordingly, the replacement portfolio is the underpinning of the commission’s evaluation and approach to the regulatory asset determination.”
The PSC pointed out that major components of Consumers’ plan — which included the purchase of a gas-fired plant and the expansion of the 60-MW Filer City coal plant in Michigan — “are either not near the conclusion of the regulatory process or, in the case of the gas plant purchase, have not yet been filed,” even at the “tail-end” of a seven-month proceeding.
Consumers spokeswoman Katelyn Carey said the decision not to pursue a 2018 Palisades shutdown was made after careful review by both parties.
“Moving ahead under the terms of our current Palisades’ power purchase agreement through 2022 is the best path forward. We appreciate the thoughtful, deliberate approach by all parties during the process and remain committed to delivering affordable, reliable, safe and clean energy to our customers across Michigan,” Carey said in a statement.
Entergy last December announced it would close Palisades on Oct. 1, 2018, citing unfavorable market conditions for nuclear generation and more economic alternatives. (See Entergy, Consumers Announce Closure of Palisades Nuke.)
In a press release Thursday, the company said that it “remains committed to its strategy of exiting the merchant nuclear power business.”
“We greatly appreciate the continued patience of our employees and the local community in Southwest Michigan throughout this regulatory process, and we will continue to focus on the plant’s safe and reliable operations,” Arnone said. “Entergy will continue to make all necessary investments and maintain appropriate staffing, in accordance with strict licensing standards.”
Local media outlet MLive reported that some of Palisades’ 600 employees celebrated the news.
Entergy said it expects to free up $100 million to $150 million in cash flow through keeping the PPA in place. Revoking the termination also enables the company to amortize and depreciate refueling outage costs and capital expenditures, with those cost to be included in operational results, rather than incurred as expenses.
As recently as late July, officials from the Nuclear Regulatory Commission were attending citizen meetings on Palisades’ decommissioning process, with some nearby residents concerned about on-site storage of radioactive materials. NRC said that a reserve account for Palisades contained $425 million to cover the potentially 60-year decommissioning process.
During a February earnings call, Consumers CEO Patti Poppe said CMS would improve its financial position by terminating the Palisades nuclear plant PPA in favor of employing more energy efficiency, demand response, renewable power and coal-to-gas switching. She added that Consumers’ substitute capacity plan for the “above-market” PPA would have replaced a single, big-bet capital project with many smaller options carrying less risk, and that CMS could replace other PPAs by building its own plants.
MISO’s proposed multiyear evaluation on the future impact of integrating renewable energy will consist of 10 separate studies, with each focused on projected grid conditions at steadily increasing levels of renewable penetration.
But the RTO’s sweeping approach is drawing mixed reactions from stakeholders.
MISO policy studies engineer Jordan Bakke said the evaluation will first model current renewable penetration — about 8% of the resource mix. It will then examine growing system complexity in increments of 10% renewable resource penetration, concluding with an RTO system powered 100% by renewable sources.
Existing renewables in MISO footprint | MISO
At each 10% checkpoint, MISO will assess systemwide ramping capability, operating reserves, transmission congestion, voltage and frequency stability, and loss-of-load expectation, among other data.
“Between some milestones, the system complexity might not increase much, but at other points, it could increase a lot — and those are our inflection points,” Bakke said during a Sept. 27 Planning Advisory Committee meeting. “We currently don’t know where these inflection points lie.”
The evaluation will attempt to identify when the growth of renewables and the retirement of baseload units require changes in the structure or operation of the system, something MISO has not attempted to answer until now, Bakke said. (See MISO to Conduct Long-Term Renewable Integration Study.) It also aims to predict:
How and when system reliability will be impacted by heavy renewable output;
Whether there are limits to the amount of wind and solar generation MISO can support;
How long until energy storage becomes a requirement;
What parts of the grid will be stressed first; and
How much renewable energy can be deployed before substantial system changes are needed.
The study will also explore what solutions will best mitigate system stressors, Bakke said, whether they be new transmission lines or buses, energy storage, better dispatch availability, demand response measures or better coordination efforts.
Bakke said he would return to later PAC meetings to discuss what MISO has discovered at each study milestone. The study doesn’t have a definitive end date, but Bakke said MISO would likely examine the effectiveness of continuing the study after a year.
Wind on the Wires’ Natalie McIntire said the study may not be “helpful or accurate” given that MISO has not yet reached a 10% renewable penetration and will take several years to achieve a 50%. Transmission could look very different by then, she noted.
“We’ve seen a lot come on in a relatively short amount of time,” countered Bakke, adding that MISO is especially interested in studying the system at a 30-60% renewable penetration, which may become a reality.
Other stakeholders pointed to the high number of renewable projects lined up in MISO’s interconnection queue, which could quadruple wind capacity in some parts of the footprint.
“We started out calling this a breakpoint study,” said MISO Director of Planning Jeff Webb. “If the systems breaks here, what do you do to fix it? And if it breaks here, what do you do to fix it?”
Some stakeholders said the study seems like a high-risk, low-reward endeavor, considering that advances in renewable technologies could solve their own shortcomings by then. Others suggested that generation and transmission owners might question the relevance of study results going out to 2050.
“We’re asking what things do we need to care about in 10 years, and what things do we have to care about in 30 years,” Bakke explained.
Xcel Energy’s Drew Siebenaler said that the study could yield a “holistic look” at renewables and system capability. “We fully support this effort as long as it takes,” he added.
