The Organization of MISO States on Monday called on FERC to order the nation’s utilities to cut rates in response to a recent reduction in federal corporate taxes.
OMS board members last week unanimously approved sending the commission a letter outlining their position after Executive Director Tanya Paslawski introduced the idea during a conference call.
“I don’t think it’s anything controversial here … but we want to make sure everyone is comfortable,” Paslawski said. “We’re looking to file this fairly quickly.”
North Dakota Public Service Commissioner Julie Fedorchak was the first to express her support.
The letter, signed by OMS Chairman Ted Thomas (also chair of the Arkansas Public Service Commission), encourages FERC to move quickly to ensure customers receive the maximum benefits associated with the recent reduction in the federal corporate tax rate. The tax reduction “directly impacts the cost of service for regulated utilities across the country,” the letter said.
OMS noted that many of its members have already taken steps “to preserve the value of these cost reductions” for ratepayers within their own jurisdictions and that it is in the public interest that the savings be realized by all customers, including those for electric transmission.
“As such, the OMS members join the chorus of parties urging FERC to take all necessary action to preserve the benefits of the cost reduction from lower corporate tax rates for customers in the form of lower transmission rates for entities within its jurisdiction,” the organization said.
Ever since President Trump last month signed the Tax Cut and Jobs Act, reducing the corporate tax rate from 35% to 21%, state officials across the country have called on utilities to pass the savings to their ratepayers — and some utilities have vowed to do so. The Organization of PJM States Inc. has already sent a similar letter to FERC. (See Utilities Likely to Pass Tax Bill Gains to Customers.)
Several OMS associate members elected to join in the letter, including the Indiana Office of Utility Consumer Counselor, the Office of Consumer Advocate of Iowa, the Michigan Agency for Energy, the Minnesota Office of the Attorney General and the Citizens Utility Board of Wisconsin. The Alliance for Affordable Energy in Louisiana also said it supported the letter.
At Thursday’s open meeting, Commissioner Robert Powelson expressed his support for a measure. “I hope we do our part to make sure these tax benefits are accrued to energy users here in America,” he said.
Chairman Kevin McIntyre told reporters after the meeting that he agreed with Powelson’s sentiment and that the commission was considering its options.
OKLAHOMA CITY — SPP’s Strategic Planning Committee last week decided it will respond to FERC’s request for a definition of “resilience,” rather than losing valuable time turning the effort over to a newly created task force.
The commission on Jan. 8 rejected Energy Secretary Rick Perry’s call for cost-of-service payments to coal and nuclear generators, instead creating a new docket (AD18-7) requiring RTOs and ISOs to answer two dozen questions about how they define and assess resilience. FERC said it will use the response to determine whether additional action is necessary. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
Grid operators must respond by March 9.
American Electric Power’s Richard Ross, stressing the importance of stakeholder feedback, asked, “Will the creation of a task force end up consuming two-thirds of the time needed to get feedback?”
During the SPC’s Jan. 18 meeting, SPP staff initially suggested creating a forum in which they could solicit member concerns and input on resiliency issues, but they eventually yielded to the SPC’s management role to save time.
“Let’s start the discussion and see what happens,” SPP CEO Nick Brown said. “Using the whole Strategic Planning Committee is the best approach. Let’s let our team of experts put straw comments together, and see where they fly.”
Brown assured the committee he is, and will be, in “constant contact” with his counterparts to track progress at other RTOs, and said there was little appetite for asking FERC for an extension.
“I suggest we move ahead as best we can, using our existing stakeholder process,” he said.
Asked whether this was the commission’s effort to end up with resiliency standards, Brown said he didn’t know. “I think FERC is just looking for guidance on this. It’s a new commission, and there’s a lot of different thoughts on that commission.”
FERC has started the dialogue by inviting feedback on its suggested definition of resilience: “The ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”
SPC Chair Mike Wise, with Golden Spread Electric Cooperative, said he would work with the committee’s staff secretary Michael Desselle and SPP General Counsel Paul Suskie to create a timeline and process for gathering input.
Energy-only Resources Report Leads to Discussion, not Results
A staff report on including energy-only resources in SPP’s transmission planning process generated significant debate but did not result in an action item.
Staff reminded the committee several times that it was only presenting a status report, and that it would provide more information in the future.
“It’s pretty clear from the discussion we have some concerns,” Wise said. He and Desselle “want to spend some time looking at this before we get back to you.”
Staff said they are attempting to develop and adopt policies that better align SPP’s generation interconnection, transmission service and integrated transmission planning processes to “provide value proportional to cost when considering capacity and energy-only resources.”
Jay Caspary, SPP’s director of research, development and special studies, said this will address a perception that there is an “inequity of costs associated with market access and transmission expansion” allocated to load-serving entities when compared to non-LSE interconnection customers.
As the discussion dug deeper into the weeds, it was evident that stakeholder concerns ranged in many different directions, from the meaning of firm and non-firm transmission service to the length of time it takes proposed projects to get through the interconnection queue.
Caspary highlighted one equity issue as the “big one”: LSEs or merchants with energy resources compete equally in the market with those that have capacity resources and typically incur lower costs with associated market access.
“We could determine all network load in the footprint is firm,” Wise said. “That’s one way to eliminate much of this issue.”
“That may be very well where we end up,” said Lanny Nickell, SPP vice president of engineering. “We were trying to limit our creative thinking to what we felt we could accomplish. These are just ideas, not the end-all, be-all solutions to all the concerns we’ve been hearing.”
Staff said they would narrow a list of “modification considerations” — and “not proposals,” Nickell clarified — and incorporate the SPC’s feedback into a whitepaper, to be presented to the committee in the future.
Until then, much of the project’s burden could fall onto the Generator Interconnection Improvement Task Force (GIITF), which has been asked to address the overloaded interconnection queue and new requirements from FERC’s proposed rulemaking initiatives.
The GIITF in April intends to share with the Markets and Operations Policy Committee details on its three-stage process to clear the queue’s backlog. The group expects its next major issue to be rules accommodating battery storage, following a “dozen or so” requests for storage in the latest queue.
“That’s a bigger and bigger item for us to deal with,” said SPP’s Steve Purdy, the GIITF’s staff secretary. “We have a lot to accomplish by October.”
The MOPC recently granted the task force a one-year extension to develop a replacement for SPP’s current interconnection process. (See “Generator-Interconnection Task Force Extended for 1 Year,” SPP Markets and Operations Policy Committee Briefs.)
Brown told the SPC that the Corporate Governance Committee is reviewing SPP’s governance structure to ensure it still matches where the RTO is today — and will be soon with the possible integration of the Mountain West Transmission Group.
SPP’s footprint touches 14 states, stretching from East Texas to the Canadian border, having added Nebraska utilities and the Integrated System since 2009.
“We need to put some thought into the governance structure as we continue to grow,” Brown said. “Is a committee structure we put in place in 2003, and changed incrementally, appropriate for where we are today? It’s time. We just haven’t sat down and taken a detailed look.”
The Finance Committee is also moving forward with changes to increase transparency into SPP’s budget, which Brown said raises questions about the RTO’s withdrawal fee.
“All those things fit together,” he said, promising the SPC and Board of Directors will stay informed of the progress.
Controversy is swelling over the February 2017 spillway collapse at the Oroville Dam in Northern California, after local officials last week filed a scathing lawsuit alleging corruption at the state’s main water agency and lawmakers called for FERC to delay the facility’s relicensing.
“Decades of mismanagement and intentional lack of maintenance” by the California Department of Water Resources led to the federally declared disaster, according to allegations in the Jan. 17 lawsuit filed by the City of Oroville against the department. Filed with the California superior court in Butte County, the suit describes maintenance issues and a culture of poor supervision, fabricated inspection reports and corruption at the agency.
“For years, DWR supervisors were more interested in lining their own pockets than ensuring the safety of the facility and its workers. Important maintenance projects were delayed or never completed, and substandard supplies were used to address vulnerabilities in the dam’s armored spillway,” the lawsuit alleges.
Oroville is home to the Hyatt and Thermalito power plants totaling 933 MW of capacity, which had to be shut down during the incident. During the dam’s 2005 FERC relicensing proceeding, three environmental groups requested that the state pave the hillside below the emergency spillway to avoid erosion. The spillway failure generated criticism of both the DWR and FERC for ignoring the previous warnings. (See Local Officials Appeal to FERC as Oroville Water Levels Recede.)
The court filing alleges a “toxic culture” at the department, describing incidents of racist and sexist behavior, employee theft and other corruption. It describes how events around the incident unfolded, including the interaction of local law enforcement with DWR officials prior to and during the evacuation, which caused chaotic and dangerous road conditions and massive traffic jams. A complaint filed through the state Government Claims Program over the Oroville situation was rejected last July because it was determined it would be better resolved by the courts, the lawsuit says.
The lawsuit does not specify financial damages but does cite physical damage to city infrastructure, equipment and personal property as well as costs related to the evacuation, loss of tax and tourism revenue, and emergency and law enforcement services.
DWR spokesperson Erin Mellon said the department does not comment on pending litigation.
On Friday, U.S. Rep. John Garamendi (D), whose district is near Oroville, petitioned FERC to postpone the pending relicensing of the dam, citing the incident and saying “a failure by FERC to delay relicensing of the Oroville Dam would be a serious abdication of its regulatory responsibility.” A week earlier, nearly two dozen California state legislators filed in support of delaying the license.
Blowback over New DWR Director
The DWR has had four directors since the beginning of 2017, when Bill Croyle took over as acting director after Mark Cowin’s nearly seven-year stint. Cindy Messer briefly took over from Croyle in July 2017 until Gov. Jerry Brown appointed Grant Davis to the role.
Davis only led the department until this month, resigning after an independent forensics team released its report on the dam failure. (See Report: Regulatory Failure Caused Oroville Incident.) He was the signatory to the department’s Dec. 20 relicensing application to FERC, and he noted that the spillway incident followed California’s wettest January and February in more than a century.
Brown appointed Karla Nemeth to replace Davis on Jan. 10. That decision has stirred controversy, as TheSacramento Bee reported last week, because Nemeth is married to Tom Philp, executive strategist of the Metropolitan Water District of Southern California, a key member of a group of public agencies known as the State Water Contractors, which are the main recipients of water stored behind the Oroville Dam.
The City of Oroville’s lawsuit alleges the State Water Contractors “lobbied DWR to defer maintenance at [State Water Project] facilities, in order to reduce their own costs” and used their influence to defer needed maintenance at the facility.
Metropolitan Water District is also involved with negotiations around Brown’s $17.1 billion water tunnels proposal, a large-scale project opposed by many Northern California officials and environmentalists.
Real-time price data from 2018 indicate the ISO-NE grid is nearly free of congestion, stakeholders learned during a Planning Advisory Committee teleconference last week.
ISO-NE System Planning Engineer Victoria Rojo presented the PAC with an analysis of historical market and operational data, saying “the small congestion component of the locational marginal prices suggests there is little congestion on these interfaces.”
| ISO-NE
The analysis showed that interface flows typically operate closer to the limit during on-peak hours and that portions of the system far from load centers — especially northern Maine — have high negative loss components. Rojo attributed the Maine negative line losses to new wind energy resources.
“We are effectively close to a congestion-free system,” said Michael Henderson, the RTO’s director of regional planning and coordination.
West Central Mass 2027 Tx Needs Assessment
ISO-NE will conduct a 2027 needs assessment for the Western and Central Massachusetts (WCMA) study area to examine any potential transmission needs 10 years out and determine their time sensitivity.
West Central Mass Study Area | ISO-NE
The study will consider future load distribution; resource changes in the area based on Forward Capacity Auction 11 results; 2017 solar and energy-efficiency forecasts; reliability over a range of generation patterns and transfer levels; and all applicable NERC, Northeast Power Coordinating Council and ISO-NE transmission planning reliability standards.
Comments on the preliminary draft study are due by Feb. 4 and the study should be complete in the second quarter.
Critical Load Level and Need-by Date Determination
Senior transmission planning engineer Pradip Vijayan presented staff analysis to determine the critical load level (CLL) and a need-by date (NBD) for steady-state, peak-load needs on short circuits.
The study noted that in past needs assessments, a “year of need” was used to denote summer peak load needs likely to be required within three years. However, for time-sensitive needs, the Tariff requires a specific NBD.
New England Subarea Model | ISO-NE
The RTO performs a CLL analysis for each identified need, and the results inform market participants about the quantity and general location of resources that would either satisfy the need or defer it for regulated transmission solutions.
For a time-sensitive need, the calculated CLL signals at what load level an identified need would be eliminated — which may call for additional reduction in New England load.
OKLAHOMA CITY — SPP told members last week it and its Market Monitoring Unit will file separate reply briefs in response to FERC’s December order that found the RTO was suppressing investment signals by not allowing quick-start resources (QSRs) to set LMPs.
The commission issued a Section 206 order requiring SPP to change its Tariff to address quick-start pricing (RM17-3). FERC said it found the RTO’s approach to the resources’ pricing to be “inconsistent with minimizing production costs” and suggested several changes it could implement. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
Under a 206 filing — “fairly new to SPP,” said Market Design Director Richard Dillon — FERC can unilaterally make changes to an RTO’s or ISO’s rates, terms or conditions. The reply briefs are due by Feb. 12, with a final order expected within six months of that. The MMU will file its brief after the RTO. Neither Dillon nor MMU Executive Director Keith Collins revealed what they will say in their briefs.
“A quick-start unit provides a product other [resources] can’t,” Dillon said. FERC “wants the value of the product to be reflected in the LMP itself.”
In the meantime, SPP staff said it will continue its work on three open revision requests addressing QSRs. Securing the Markets and Operations Policy Committee’s unanimous approval last week of a revision request that corrected and clarified a previous revision was a first step.
Staff developed RR 256 as it began working on the previous revision request’s implementation details. It said the revision addresses a market inefficiency “inadvertently” created in RR 116 and eliminates a potential gaming opportunity. RR 116 was approved in October 2015 but has yet to be filed with FERC. Two other quick-start related Tariff changes, RR 137 and RR 142, have also been approved by SPP stakeholders but not yet filed.
Dillon said the revision requests are built on top of each other and reflect stakeholders’ “desires and corrections,” but they will not be filed with FERC until the commission rules on the Section 206 docket.
RR 116: Provides the primary language for the new QSR logic and replaces “quick-start resource” with “offline supplemental reserve resource” for those resources supplying offline supplemental reserve.
RR 137: Updates previously removed enhanced combined cycle language referencing QSR limits and the Tariff’s Appendix G for QSR changes.
RR 142: Clarifies that QSRs are ineligible to register as multiconfiguration combined cycle resources.
In its order, FERC said SPP should:
Commit and dispatch QSRs in real time consistent with minimizing production costs, subject to operational and reliability constraints;
Remove the option for enhanced energy offers for QSRs that incorporate commitment costs in the incremental energy curve; and
Consider both registered and unregistered QSRs in quick-start pricing to ensure prices reflect the cost of the marginal resource.
Golden Spread Electric Cooperative’s Mike Wise said the revision requests are unresponsive to the FERC order and “come very short of the mark.” Dillon admitted the changes do not cover everything in the 206 order, “but they’re moving in the same direction.”
Dillon said addressing all of FERC’s directives in the 206 filing would result in significant market changes for SPP. He pointed out SPP’s pricing is ex ante (planned), and that an ex post market (actual outcomes) would require major software changes.
“We don’t know what the final order will look like,” he said. “When we get an actual order from FERC, we’ll have another RR incorporating additional direction from FERC.”
Oklahoma Gas & Electric’s Greg McAuley said his company would prefer SPP file the revision requests, rather than wait on FERC. “The concern is stakeholders have already indicated a willingness to do this. As an entity with brand new quick-start resources coming online and available, what we’ve been working on is very important to us.”
“A bigger issue is credibility,” Dillon countered. “We used to have a reputation of knowing what we were doing and being really sharp. If we make some filings inconsistent with the very 206 filing FERC gave us, that calls into question we know what we’re doing. We don’t want to dig that hole any deeper.”
Complicating matters is SPP does not yet have a definition for QSRs in its Tariff, as do the other RTOs. Stakeholders have suggested a minimum run time of one hour or less to qualify as a QSR.
“Johnny, rosin up your bow and play your fiddle hard,
’Cause hell’s broke loose in Georgia and the Devil deals the cards.”
There’s a process problem with the Georgia Public Service Commission’s Vogtle decision, and there’s a substance problem.
Process Problem
Georgia commissioners publicly and vehemently stated that Vogtle should be completed.[1] And then they had a hearing on whether Vogtle should be completed. See the problem?
Regulators are supposed to make reasoned decisions based on records. It’s hard to do that before you have a record.
“Sentence first! Verdict afterwards,” as the Queen said in “Alice in Wonderland.”
Substance Problem
Last September, my column showed that the original “need” for Vogtle, in the form of a projected increase in customer demand, had basically disappeared.[2] And with simplifying assumptions favorable to Vogtle, and using Lazard cost estimates, completing Vogtle would impose excess costs of $23.6 billion on Georgia consumers over the next 40 years.
Here’s a quick quiz: After eight years of construction, what percent of Vogtle is constructed? Answer in footnote below.[3]
So there was a hearing. Or more like Kabuki theater. The Public Interest Advocacy Staff (PIA Staff) of the Georgia commission showed:[4]
Because of multiple flaws in Southern Co.’s case, “the project is uneconomic on a going forward basis by $1.6 billion.” The commission’s Advisory Staff agreed with PIA Staff that completing Vogtle is uneconomic at the cost estimated by Southern.[5]
“Certain costs [$1.5 billion, excluding Toshiba’s parental guarantee] for which the company is seeking recovery from ratepayers resulted from project mismanagement.”
“Had the commission been more accurately informed by the company as to the depth of the problems facing the project, the commission would have had the opportunity to assess the project status and make different decisions earlier on in the construction, when sunk costs were not so daunting an issue.”
Giving Vogtle co-owners “the right to abandon the project if any company costs are disallowed for any reason, including fraud, failure to disclose a material fact or criminal misconduct” was a “threat” and “unconscionable.”
Southern, of course, disputed all this.
Given the enormity of these issues and the long-term consequences of a decision to complete or not complete Vogtle, one would have expected a deliberate, careful analysis of the record and a reasoned decision.
Instead, the last day of hearings was Dec. 14, briefs were required five days later and the commission made its decision two days after that. Speed readers, I guess.
Are you ready for the decision itself? The Georgia commission without any explanation at all simply proclaims:[6]
“Based upon careful consideration of all the evidence in the record, the commission finds as a matter of fact and concludes as a matter of law that it is appropriate to continue construction of Vogtle Units 3 & 4 under the terms set forth in this order.”
Georgia, that’s all the explanation you get. C’est la vie.[7]
But what should consumers expect from regulators who had announced their decision before the hearing? Why waste ink?[8]
More Project Delays Rewarded
Going forward, Georgia consumers have no protection against continuing project delays and overruns.[9] The Georgia commission order claims that it incents performance by reducing return on equity if target dates aren’t met.
Unfortunately that is just wrong. Reduced ROE during delays is only for the periods of delay. After the project is in commercial operation, that ROE becomes part of the rate base, upon which Southern gets a generous return for at least 40 years. That is why Southern already will make an extra $5.2 billion over the life of the project from the delays to date.[10] Nice work if you can get it.
Vogtle Nuclear Power Plant
The longer Vogtle takes to complete, the more Southern makes.
And every electric consumer in Georgia is on the hook for whatever Vogtle ends up costing.
What site selection advisor for a large consumer of electricity will recommend locating a new facility in Georgia? Because there is no competition in Georgia,[11] any new business would have unlimited exposure to the Vogtle plant. Moody’s Investor Service already downgraded JEA because it owns 206 MW of Vogtle.[12]
Customer Refund Gimmick
One last note on the Georgia commission decision: It directed that Southern refund part of the Toshiba/Westinghouse Electric settlement payment to consumers, $25 per customer per month for three months, with a bill line item saying “Vogtle Settlement Refund.” Great PR, but this refund money isn’t coming from Southern. It’s money that otherwise would have been credited against the cost of Vogtle.
So consumers effectively will be paying Southern a generous return on their refunds for decades. Sort of like your credit card company sending you a $75 gift card, but then that $75 shows up on your next bill as a cash advance. Which you can’t pay off for the next 40 years.
Oh, sorry, one more thing: The Georgia commission authorized a token 5-MW solar project to be located at, you guessed it, Vogtle. No consideration of whether that project size or location made any sense. But even more rate base for Southern.
The Sad Reality
The sad reality is that Vogtle never made sense, and this became obvious years ago. The Vogtle owners failed to oversee the failures of Toshiba and Westinghouse, failed to report the failures to the Georgia commission, and failed to provide realistic project costs and schedules. The hole became billions deeper as a result, and Southern’s past and future profits grew as a result.
Instead of holding the Vogtle owners accountable for their failings, the Georgia commission is more concerned with not appearing to have made consumers pay something for nothing. So the Georgia commission approves continuing an uneconomic project, gives Southern and the new project contractor an even bigger blank check than before, and maintains the incentive of higher profitability from greater delays.
The flogging will continue until morale improves.
Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.
Adding to the incredulity is that terms of the commission decision were reviewed with Southern in advance of the commission meeting. “Although Echols said he did not want to get into details about his interaction with Georgia Power over the new conditions, he added, ‘Ultimately, they were read in and gave feedback’ on those restrictions.” http://chronicle.augusta.com/news/2017-12-21/georgia-public-service-commission-vote-allows-plant-vogtle-proceed. ↑
Not part of the decision is a motion by one of the commissioners on what the decision should be. This motion refers to the uncertainty of future natural gas prices, and how Vogtle can be a hedge against high gas prices.Of course future energy prices can’t be known. But the salient fact is that a forecast of future natural gas prices is effectively a mean. Lower gas prices would mean Vogtle is even more uneconomic. Higher gas prices would mean Vogtle is less uneconomic and might even be economic. But decisions need to be based on the mean, not on one extreme or another. And here’s another important point: If the gas price hedging value is significant the right thing to do is suspend Vogtle at a relatively trivial cost of $112 million for up to 10 years, which cost comes from Southern’s own consultant. http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=169459 (Black & Veatch Deferral Study). The Georgia Commission decision makes no mention of this option. ↑
“As a result of the delays experienced by the project, the company will make considerably more profit over the lifecycle of the units than it would have had the project been completed on time. The company’s profit will increase from approximately $7.4 billion to approximately $12.6 billion over the unit’s entire lifecycle.” http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=170562 (page 8). ↑
As I’ve pointed out before, Vogtle and the lack of competition are joined at the hip. ↑
CARMEL, Ind. — MISO is seeking to more closely harmonize its load forecasting process with the four 15-year future scenarios it creates to support long-term transmission planning, but stakeholders are wary of two ideas being floated by the RTO.
“I think it’s time we move to where the … load forecast is future-dependent,” John Lawhorn, MISO senior director of policy and economic studies, said at a Jan. 17 Planning Advisory Committee meeting.
Lawhorn said that the futures created for the MISO Transmission Expansion Plan could link up with the load forecast in one of two ways: require load-serving entities to supply detailed planning-level data for each of the futures; or use the RTO’s “independent” load forecast as a starting point to create forecasts for each future.
“In both cases, the level of information would be the same; it would include a 20-year forecast, energy efficiency, demand response [and] distributed generation,” Lawhorn said.
“It’s a paradigm shift,” he said. “It’s becoming increasingly evident that a long-term forecast is needed to study the futures,” citing the potential for MISO to swing from summertime peak planning to possible hour-by-hour planning for a future in which smaller distributed generators provide scatterings of energy.
The biggest hitch with the current forecasting approach is that MISO can’t get a clear picture of demand-side management programs, which will be instrumental in forecasting future demand, Lawhorn said.
“This is driving our planning process to areas that we haven’t yet been forced to look at in this level of detail,” he added.
Developed by Purdue University’s State Utility Forecasting Group, MISO’s independent load forecast does not draw on any of the futures, which include “limited,” “continued” and “accelerated” fleet change predictions, as well as a scenario in which distributed generation and emerging technologies gain popularity. The independent forecast also does not account for individual load forecasts produced by MISO’s LSEs, but instead relies only on publicly available information to predict summer and winter peak energy demand for the RTO’s 10 local resource zones along with systemwide peaks.
Unlike the 10-year forecasts produced by LSEs, the Purdue forecast is for informational purposes only — not tied to any official MISO predictions — with an Applied Energy Group study lending the independent load forecast its projections for EE, DR and DG. But the RTO now thinks either the Purdue or LSE forecasts could perform a larger role in transmission planning.
MISO says its pace of fleet evolution “highlights the need to create a new source of load forecasts tailored for long-term economic planning.”
“Our process lacks transparency and it lacks … the detail needed to effectively and efficiently move energy to all areas of the MISO footprint,” Lawhorn said. He also said the 140-plus separate LSE load forecasts currently lack a common set of assumptions.
Two Approaches
If the RTO decides to have LSEs prepare more detailed forecasts, they would have to ready four separate 20-year forecasts, a total of 8,760 hourly load shapes, 20 years’ worth of demand-side management growth predictions, and four iterations of program penetration for EE, DR and DG.
MISO could adopt the LSE-centered approach by the 2021 MTEP at the earliest, Lawhorn said, noting that it would take a minimum of two years to modify the RTO’s member website to accept more detailed information.
Currently, LSEs submit 10-year demand and energy forecasts, extrapolated for another 10 years to develop a 20-year forecast.
“By having a 20-year forecast, you might be outrunning the headlights of state regulators and local planners,” said David Harlan, president of consulting firm Veriquest Group.
“That level of specificity is where the industry is heading,” Lawhorn replied.
MISO’s second load forecasting option involves a third-party consultant like Purdue developing a 20-year demand and energy forecast for each local resource zone by future scenario. Such a system could be in place by MTEP 19.
PAC Chair Cynthia Crane asked whether MISO plans to calibrate a long-term third-party forecast against the shorter forecasts furnished by LSEs if it takes the second route.
“Oh, absolutely,” Lawhorn said.
LSE Ability to Forecast
Stakeholders are divided over how difficult it would be for LSEs to provide more detailed forecast data.
Indianapolis Power and Light’s Lin Franks said there’s no reason MISO couldn’t begin now to use more detailed LSE information for load forecasts.
Lawhorn responded that it’s a “fairly considerable task” to coordinate forecast information from more than 140 LSEs, noting that not all of them are prepared to offer that level of detail. MISO will instead issue a survey to determine the feasibility of producing 20-year forward-looking data, he said.
Customized Energy Solutions’ Ted Kuhn pointed out that forecasts are only worthwhile if MISO develops a process for historically assessing their accuracy. He said the RTO must be able to compare forecasts with actual demand.
Minnesota Public Utilities Commission staff member Hwikwon Ham said he thinks “the independent load forecast is as good as the input used.”
American Electric Power’s Kent Feliks said it’s a “daunting amount of work to require all 140-plus LSEs to provide 20-year forecasts.”
“It seems like an awful lot of resources spent … for little improvement,” he said.
Other LSE representatives at the meeting said creating a load forecast would be a nominal challenge, as they already collect the data needed to prepare forecasts for each MTEP future.
WPPI Energy’s Steve Leovy asked MISO to be more specific about what kind of forecasting information LSEs will be asked to provide. “I’m concerned with what I see, to be blunt, is a half-baked proposal,” he said.
Madison Gas and Electric’s Megan Wisersky said that LSEs will not be able make an informed choice between the two approaches until they research the costs of preparing more in-depth forecasts.
Lawhorn said MISO is collecting input on the new pair of proposals, and that he would return to the PAC in June to discuss the RTO’s take on the prevailing stakeholder opinion.
FERC will furlough all but 49 of its 1,465 employees if it runs out of money because of a prolonged federal government shutdown.
The first shutdown since 2013 began Saturday after the Senate failed to reach agreement on a spending plan. On Monday night, however, President Trump signed a bill to fund the government through Feb. 8.
The commission’s contingency plan says it will continue normal operations until its funds from prior year appropriations are exhausted. After that, it will continue only “excepted” activities, such as protecting life and property (e.g., inspections of LNG facilities), monitoring for physical and cyber threats to infrastructure, and market monitoring. “The excepted staff will perform a minimum level of these oversight roles, to monitor for urgent matters,” the plan says.
FERC staff and commissioners pledge allegiance at open meeting Thursday. Most staff would be furloughed during a prolonged shutdown but the commissioners will remain at work | FERC
Because the five commissioners will continue working through any hiatus, FERC also will keep some legal staff working to provide advice.
The commission will stop accepting filings from the public and postpone deadlines and due dates for all pending matters not related to excepted activities. It will seek stays from all cases pending in federal courts. “If the courts deny the stay and explicitly or implicitly rule that FERC participation in these matters is authorized under the protection of life and property exceptions provided in 31 U.S.C § 1342 or some other applicable provision of law, FERC staff will be required to meet obligations established by these courts.”
In addition to retaining 49 staffers (3.4% of the total), the commission will also maintain 18 contract workers to provide physical security for FERC facilities and information technology support.
The Interior and Energy departments expect to furlough about three-quarters of their workforces. EPA could lay off 95% but says it has “sufficient resources to remain open for a limited amount of time.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:50)
Members will be asked to endorse the following proposed manual changes:
B. Manual 38: Operations Planning. Revisions developed from periodic review to include protection system/relay communication outages and PJM assessment of impact.
Members will be asked to approve a problem statement and issue charge at their first reading to address how gas-fired generators should be compensated if PJM orders them to switch to alternative fuel sources, such as oil or a different pipeline. (See “Emergency Pipeline Switching Instructions Sparks Rights Debate,” PJM MIC Briefs: Jan. 10, 2018.)
4. RERRA Review of Energy Efficiency Participation (10:20-10:40)
Members will be asked to endorse Tariff and Reliability Assurance Agreement revisions associated with the Demand Response Subcommittee proposal for the relevant electric retail regulatory authorities (RERRA) review of energy efficiency resource participation in the capacity market. (See “Rules Endorsed for Enforcing Regulator Requirements on EE,” PJM MIC Briefs: Jan. 10, 2018.)
5. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (10:40-11:30)
PJM management will discuss its recommendation to the Board of Managers that the RTO file with FERC a capacity repricing proposal. Members will be asked to endorse proposed Tariff revisions for the Independent Market Monitor’s MOPR-Ex proposal to extend the minimum offer price rule to all resources. (See PJM Going it Alone on Capacity Repricing Plan.)
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to endorse:
B. Tariff revisions related to the procedures associated with the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
Members will be asked to endorse revisions to the Tariff, Manual 28: Operating Agreement Accounting and Manual 6: Financial Transmission Rights resulting from special sessions on FTR issues. The revisions will address changes to long-term FTR modeling for future transmission expansion, streamlining management of overlapping FTR auctions and allocating any surplus funds from day-ahead congestion and FTR auction revenue. (See “FTR Changes in the Works,” PJM MIC briefs: Dec. 13, 2017.)
2. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (1:40-2:10)
Members will be asked to endorse proposed Tariff revisions associated with the proposal developed by the CCPPSTF. (See MRC item 5 above).
3. Incremental Auction Senior Task Force (IASTF) (2:10-2:25)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions for proposal A”, which would reduce the number of Incremental Auctions from three to two following each Base Residual Auction. PJM says the change will reduce the opportunities for BRA sellers to “shop” for the cheapest replacement capacity while allowing them to cure a physical inability to satisfy their commitments. (See “Incremental Auction Revisions Endorsed,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)
4. RERRA Review of Energy Efficiency Participation (2:25-2:40)
Members will be asked to endorse proposed Tariff and Reliability Assurance Agreement revisions for the RERRA review of energy efficiency resource participation in the capacity market. (See MRC item 4 above).
A House Energy and Commerce Committee panel Friday heard testimony from federal officials and stakeholders on Republican legislation to expand LNG exports and revise the Public Utility Regulatory Policies Act. Support for the bills, introduced late last year, fell along party lines at the hearing.
PURPA Modernization
The PURPA Modernization Act of 2017 (H.R. 4476), introduced by Rep. Tim Walberg (R-Mich.) in November, would substantially reduce the number of PURPA qualifying facilities from which utilities would be forced to buy power.
Currently, QFs of 20 MW or larger are presumed to have nondiscriminatory access to the wholesale competitive markets and are thus ineligible to invoke utilities’ must-purchase obligation. The bill would reduce this threshold to 2.5 MW.
It would also make it harder for QF developers to game FERC’s 1-mile rule — the presumption that QFs located 1 mile or more apart from each other are separate facilities — by making that presumption rebuttable.
State regulators also would be allowed to exempt utilities from having to purchase from QFs if they determine that the utilities have no need for their power, or if utilities use integrated resource planning and conduct competitive procurement processes.
Testifying on behalf of the National Association of Utility Regulatory Commissioners, Montana Public Service Commission Vice Chairman Travis Kavulla praised the bill. “This legislation is an important and significant leap forward in providing us with the ability to secure a reliable and affordable energy future for the nation,” he said.
From left to right: Travis Kavulla, Montana PSC; Timothy Sparks, CMS Energy; Karl Rabago, Pace Energy and Climate Center; Paul Cicio, Industrial Energy Consumers of America; and Charlie Riedl, Center for Liquefied Natural Gas. | Travis Kavulla
Kavulla said PURPA forces state commissions to essentially guess a utility’s avoided costs, which usually results in overstated rates. Responding to a question by Rep. Bill Flores (R-Texas), Kavulla said, “The smaller the consumer base of the utility, the greater the potential magnitude of erroneous price forecasting from the regulator would be.” In the case of small municipalities and cooperatives, the city or county councils that regulate them “are probably even in less of a good position than I am to try to guess about the future market prices of energy for the purpose of establishing a rate.”
Karl Rabago, executive director of the Pace Energy and Climate Center, said the bill “proposes three significant and problematic changes to PURPA and should be rejected in favor a more measured and competition-friendly approach to addressing perceived concerns about electricity markets.”
“The real problem today is the need for modernization of the utility business model that is now more than 100 years old,” Rabago said.
LNG Exports
The Unlocking Our Domestic LNG Potential Act (H.R. 4605), introduced by Rep. Bill Johnson (R-Ohio), would amend the Natural Gas Act of 1938 to eliminate the Department of Energy’s role in approving requests to export and import gas. The NGA requires the department to determine whether import/export agreements are in the public interest before approving them. Trades with countries that have free-trade agreements with the U.S. are automatically considered in the public interest.
The bill leaves intact FERC’s jurisdiction over siting LNG terminals, as well as the president’s power to prohibit trade with countries under U.S. sanctions.
Republicans repeatedly emphasized the need to capitalize on the country’s supply of natural gas.
“We literally have more natural gas production capability in the United States than we know what to do with,” Rep. Joe Barton (R-Texas) said. The legislation “is simply an acknowledgement of that and says, ‘let’s use this economic resource that we have to benefit the rest of the world and create more economic benefit in the United States.’”
Democrats were less enthusiastic.
“I fail to see the need for almost any of the policy changes,” said Rep. Frank Pallone (D-N.J.), ranking member of the subcommittee. The bill “removes longstanding consumer protections and prevents DOE from ensuring exports of liquefied natural gas to non-free-trade-agreement countries are consistent with the public interest.”
So was Paul Cicio, president of the Industrial Energy Consumers of America, who said domestic gas supplies are not as abundant as commonly thought. Increased LNG exports could harm U.S. consumers by raising prices, he said. He called DOE studies used to determine whether trades with non-FTA countries were in the public interest “woefully inadequate.”
Cicio’s claims about the amount of domestic supply were challenged by Charlie Riedl, executive director of the Center for Liquefied Natural Gas, who said Ohio alone added 5 Tcf of proved reserves in 2016. (See No Agreement on Tipping Point for LNG Exports.)
“When we talk about a supply situation, it’s driven by market demand,” Riedl said. “As market demand continues to increase, we’re able to respond to that with supply.”
The other members of the panel, including those who only came to testify on the PURPA bill, agreed that there was no short-term threat to gas supply.
Steven Winberg, DOE assistant secretary for fossil energy, told the subcommittee that the Trump administration has taken no position on the bill. President Trump, however, has repeatedly emphasized expediting LNG exports, and Energy Secretary Rick Perry and EPA Administrator Scott Pruitt have traveled abroad to promote U.S. natural gas.
