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.
Louisiana regulators are questioning why MISO called a maximum generation event and issued instructions for conservative operations in its South region during an extreme cold snap last week.
Eric Skrmetta, chair of the Louisiana Public Service Commission, told The Advocate that he’ll seek an investigation into last week’s actions in MISO South, saying there was “no reason in the state of Louisiana for electricity to become short.” Commissioner Craig Greene said the agency would examine the electricity supply during the cold snap and look to identify ideas for better utility response in future frigid weather.
Reached by phone, a member of the PSC’s staff told RTO Insider that they were in the process of reviewing the event and declined to comment further.
MISO spokesperson Mark Brown said the RTO was able to maintain grid reliability even as extreme temperatures gripped the South and multiple generation outages posed challenges.
The RTO declared conservative operations and a cold weather alert for MISO South — which spans Arkansas, Louisiana, portions of Mississippi and part of eastern Texas — beginning Jan. 15, when most of Louisiana was under a winter weather advisory. It cautioned operators in the natural gas-heavy region to prepare for fuel restrictions.
The region set a new winter demand record of 32.1 GW on Jan. 17 as temperatures dipped to about 30 degrees Fahrenheit below normal and winter storm warnings were issued in Louisiana. The region’s all-time summer peak is 32.6 GW.
That same day, Entergy Louisiana reported that about 32,000 homes and businesses had lost power because of the winter storm, and it later thanked customers for responding to the conservation plea.
Entergy crews in snow | Entergy
The South region resumed normal operations late on Jan. 18, after the Louisiana PSC had issued a public appeal on behalf of MISO and Entergy Louisiana asking customers to conserve energy by lowering thermostats, sealing households against outside air as much as possible and postponing laundry and bathing during the unusually cold temperatures.
Louisiana tops all other U.S. states in energy consumption per capita, in part because of the number of oil refineries and manufacturing plants on the Gulf Coast, according to a report last year by the U.S. Energy Information Administration.
MISO South Executive Director of External Affairs Kent Fonvielle said the RTO shared the Louisiana PSC’s concerns about reliability.
“In extreme conditions such as this week’s bitter cold in the South, MISO delivers the value of a large footprint with a diverse energy mix and greater redundancies to address various challenges to operations,” Fonvielle said in an email to RTO Insider. “As the generation resources available to serve these extreme load conditions become strained, MISO has a set of procedures to ensure adequate supply and to keep the transmission grid stable.”
He added that, in such situations, MISO South calls on support from MISO Midwest and makes purchases from other RTOs. It’s also common for MISO to request that members activate their load control programs and issue public appeals for conservation, he said.
“It is rare for MISO to ask for conservation efforts, but ultimately those conservation efforts help protect the larger grid,” Fonvielle said. “Our role is to coordinate the best use of the power resources available across the MISO footprint so that it is reliable and cost-effective.”
Fonvielle said MISO appreciated the cooperation it received from South members, stakeholders and consumers to conserve energy during the peak conditions. He added that the RTO would perform its own review of the week’s events and have staff discussions on possible areas of improvement.
The D.C. Circuit Court of Appeals on Friday rejected New England generators’ challenge to FERC orders on scarcity prices, saying the commission had properly considered their complaints (16-1023, 16-1024).
The New England Power Generators Association had asked the court to review two FERC orders related to ISO-NE’s scarcity pricing rules and the peak energy rent (PER) adjustment, which is used to claw back some revenues earned by capacity suppliers when prices in the real-time energy market are very high.
Adjustment Events
ISO-NE each day calculates a strike price set just above the marginal cost of the RTO’s most expensive generation. It also estimates PERs — essentially the difference between the real-time energy price and the strike price — for any hour in which the real-time price exceeds the strike price (“adjustment events,” the court called them).
The PER value is deducted from each capacity supplier’s monthly payments, regardless of whether it sold energy in the real-time market at the high price. NEPGA says most capacity suppliers clear their electricity offers in the day-ahead market, receiving the day-ahead market price, rather than the real-time price on which the adjustment is based.
The commission has acknowledged that this is a “potential inefficiency” and has approved elimination of the adjustment for the 2019/20 capacity commitment year.
Procedural Failure
The D.C. Circuit dismissed on procedural grounds NEPGA’s challenge to FERC’s May 2014 order rejecting a joint filing by ISO-NE and the New England Power Pool Participants Committee.
That “jump ball” filing contained two alternate proposals to address generator performance problems. The commission said neither proposal was sufficient alone, ordering ISO-NE to submit a modified version of its proposal along with increased scarcity prices suggested by NEPOOL (ER14-1050, EL14-52).
The D.C. Circuit said NEPGA lacked standing to seek review of the order because it had not previously sought rehearing from the commission.
Not Arbitrary or Capricious
The court did act on the merits of NEPGA’s complaint alleging that the interaction between the scarcity prices and the PER is unjust and unreasonable.
FERC said the group had not met its burden under Section 206 to prove that the existing Tariff provisions were unjust and unreasonable (EL15-25). The commission said NEPGA’s evidence — data from a Dec. 4, 2014, adjustment and a back-cast analysis — failed to consider the likelihood and size of future adjustments. It also said NEPGA did not address whether increases in day-ahead energy prices and capacity price floors might offset expected increases to the PER. (See FERC Denies Rehearings on ISO-NE Pay-for-Performance.)
The court said the commission’s rejection of the complaint was not arbitrary and capricious, noting that “because we are dealing here with technical and policy-based determinations, the commission’s judgment is entitled to judicial respect.”
Second Complaint
NEPGA said the court should overturn the commission’s rejection of its complaint because of the outcome of the group’s second complaint challenging the PER, filed in September 2016.
In that filing, NEPGA provided an additional 20 months of data in arguing that the PER had become unjust and unreasonable because of the increased scarcity rates.
An uncontested settlement in that docket is pending before the commission. It would require ISO-NE to increase the daily PER strike price hourly based on the difference between actual five-minute reserve shadow prices and the pre-December 2014 scarcity prices for 30-minute operating reserves and 10-minute non-spinning reserves ($500/MWh and $850/MWh, respectively). The adjusted PER strike price would be effective Sept. 30, 2016, through May 31, 2018, when the PER is abolished.
“We note that any settlement would not fully moot this case because the second complaint proceeding has a refund effective date of Sept. 30, 2016, whereas the complaint in this case requested a refund effective date of Dec. 3, 2014,” the court said.
FERC last week denied the Louisiana Public Service Commission’s request for clarification on one matter related to a sprawling Entergy-related case before the federal commission.
The PSC was seeking to learn what specific proceeding would determine the return on equity that would apply to amended power purchase agreements that were the subject of an August 2016 order (ER16-1251). It requested the clarification following a January 2017 FERC order denying its request for a rehearing of the 2016 ruling. FERC had said the proceeding regarding the amended PPAs was not the right forum for determining the appropriate ROEs to be applied under a replacement tariff, finding the issues raised by Louisiana regulators to be outside its scope.
The PSC said “that if the appropriate ROE … is outside the scope of the instant proceeding, it does not appear the ROE will be addressed in any [FERC] proceeding.”
In its Jan. 18 ruling, FERC told the PSC it had explained in the 2016 order that issues concerning the application of ROE under Entergy’s unit power sales and PPAs are pending in the massive ER13-1508 docket. FERC also noted that it had already dismissed concerns by the PSC about applying a generic ROE to the amended PPAs.
MISO North and MISO South | MISO
FERC last week also approved an uncontested partial settlement related to adjustments in MISO Tariff transmission formula rate templates for Entergy’s operating companies (ER17-2579), directing the company to file a revised rate template in eTariff and terminating four related dockets (ER17-2579, ER16-1528, ER15-1453 and ER15-1436).
Entergy Services had objected to FERC trial staff’s October 2017 recommendation that it file a revised rate template for Entergy Gulf States Louisiana, but a settlement judge in November certified the partial settlement as uncontested.
The settlement memorializes adjustments to three items in the Entergy operating companies’ rate templates: excess accumulated deferred income taxes; certain permanent differences in income taxes; and the Entergy operating companies’ post-retirement benefit costs other than pensions for 2014 and 2015.
FERC on Thursday denied requests by New England transmission owners and the Edison Electric Institute for rehearing of its September 2016 ruling regarding complaints over the TOs’ base return on equity.
Since September 2011, numerous parties have filed complaints seeking reductions in the New England TOs’ base ROE.
The commission’s 2016 order established hearing and settlement judge procedures and a refund effective date for a complaint filed by an ad hoc group of municipal utilities, Eastern Massachusetts Consumers-Owned Systems, which contended that the New England TOs’ 10.57% base ROE (11.74% including incentives) should be reduced to 8.78% and 11.38%, respectively.
| ISO-NE
The commission’s Jan. 18 order rejected every argument made by the TOs, saying it “has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE in [a Federal Power Act] Section 206 proceeding” (EL16-64-001).
FERC in October rejected a bid by the TOs to increase their ROEs to the levels before they were lowered by a 2014 commission order vacated by an appellate court in April 2017. The commission said it would address the actual rate in a later remand order (ER15-414, EL11-66). (See FERC Rejects New England Tx Owners on ROE.)
The TOs also argued that constant litigation over the ROEs introduces risk and uncertainty in the ratemaking process.
They contended that the 15-month refund limitation in Section 206, as amended by the 1988 Regulatory Fairness Act, requires the commission to deny a complaint when a similar complaint is already pending.
“While Congress’ adoption of a 15-month refund limitation in the Regulatory Fairness Act gave public utilities some rate certainty in FPA Section 206 proceedings, the New England TOs misinterpret the level of certainty that Congress provided,” the commission said.
Following such logic “would prohibit any party from challenging a utility’s ROE as long as there is another complaint involving that utility’s ROE pending before [FERC], the commission said. “The language of FPA Section 206 does not support such a finding.”
The commission also rejected the TOs’ assertion that it had ignored “countervailing evidence regarding the cost of equity capital and the fact that the capital markets continue to remain unusual,” insisting it “had reviewed the pleadings and evidence submitted by all parties and found that the evidence raises issues of material fact that could not be resolved based upon the record before the commission. The hearing and settlement judge procedures established in the September 2016 order are the product of that review and are the appropriate vehicle to resolve the dispute.”
FERC on Thursday denied Bear Swamp Power’s request for a waiver of the requirement to include certain affiliate information in its market-based rate filings (ER17-603).
Bear Swamp, which is controlled by Brookfield Renewable Energy Group, operates the 600-MW Bear Swamp Pumped Storage Development and the 10-MW Fife Brook Development on the Deerfield River in northwestern Massachusetts.
Bear Swamp Project Map | Brookfield
In December 2016, the company filed a notice of change in status, reporting that Nova Scotia-based Emera had acquired an indirect 50% ownership in the company. Bear Swamp requested a waiver of the requirement to include Emera generation and transmission assets in its change-in-status notice and future market-based rate filings.
The company argued that Emera’s affiliates should not be included in its horizontal market power analysis and other filings because its generation capacity is fully attributed to Brookfield, and Brookfield is not privy to Emera’s acquisition activities. Emera affiliates include Emera Maine and Tampa Electric.
Bear Swamp Reservoirs | Google Maps
“Bear Swamp has not presented any compelling reason for its request,” the commission said in its Jan. 18 order. “The facts that Brookfield and its affiliates are not privy to the acquisition activities of Emera and its affiliates, and that a Brookfield affiliate controls day-to-day operations of Bear Swamp’s generation facility, [do] not affect the affiliate relationship between Emera and Bear Swamp.”
The commission directed the company to submit an updated market power analysis including Emera affiliates within 30 days.
Under FERC’s market-based rate regulations, any company controlling 10% or more of another company is considered an affiliate.
FERC last week denied a request by Southern Maryland Electric Cooperative (SMECO) to rehear a petition asking it to rule that Maryland Public Service Commission regulations on acquiring power from community solar facilities run afoul of the federal Public Utility Regulatory Policies Act (EL16-107).
Centreville, Maryland Solar Array | Paradise Energy Solutions
SMECO and Choptank Electric Cooperative had asked FERC in 2016 to issue a declaratory order that the PSC’s rules covering from which facilities and at what price state utilities must buy solar is pre-empted by PURPA. FERC declined at the time, arguing that the action was premature because the program was voluntary and neither cooperative had indicated it planned to enter into the program.
The cooperatives in December 2016 then asked the commission to grant a rehearing of the request or otherwise clarify that the ruling was without prejudice so that they could bring their complaint again if the PSC failed to address their concerns. They also requested that the filing fee be waived the second time around. Last October, SMECO filed a motion to supplement the record to include a proposed solar tariff it had filed with the PSC, along with the PSC’s recommendations in response and subsequent letter denying the proposal.
Hebron, Maryland Solar Array | Paradise Energy Solutions
SMECO argued this showed its intent to enter into the program and that it had exhausted all of its state law remedies, but FERC was not persuaded.
“SMECO’s motion does not allege any change to the facts relied upon by the commission in dismissing the petition, particularly, that the community solar systems program remains voluntary and that SMECO is not subject to the program’s regulations,” the commission wrote in denying the rehearing.
The order did clarify that the denial was without prejudice but did not waive the filing fee. Commissioner Robert Powelson didn’t participate in the order.
