It seems that New England’s grid reacts just as excitedly as the region’s fans when the Patriots play for the NFL championship.
On Thursday, ISO-NE’s newsletter, Newswire, featured a timely article about the Patriots’ ninth Super Bowl appearance last year, which saw the team come from behind in a dramatic overtime win.
As the game moved into overtime, grid operators saw demand suddenly level off and then inch back up. At times, demand increased by as much as 50 MW during overtime, the RTO said.
“We can definitely see the demand changes on the system, in real time, by what’s happening in the Super Bowl,” said John Norden, the RTO’s director of operations. “Whether it’s the beginning of the game, halftime or the end of the game, we can see changes in levels of consumer demand. Understanding what is going on in real time, from a societal level, is very important to us, and we monitor that from our control room.”
Sounds like someone has a very good excuse to watch the big game on company time.
ISO-NE has had plenty of chances to study the “Patriots effect” — and ran a similar analysis prior to last year’s Super Bowl.
| ISO-NE
The RTO is not alone in its interest in the topic. Matt Chester, an energy and policy professional in D.C., posted a Jan. 31 blog piece analyzing electric power usage data during the last five Super Bowls showing that “versus a typical Sunday afternoon/evening in the winter, home power usage was 5% lower during the Super Bowl, with big consequences for overall energy use.”
ISO-NE said Super Bowl load curves have formed consistent patterns over the years, with upticks in demand coinciding with halftime, commercials and the end of the game. These mini spikes occur when millions of people all choose the same moment to open their refrigerators, use microwave ovens and flush toilets. Many homes in New England use wells, and any use of water triggers an electric pump.
For its part, PJM showed its support of the underdog Philadelphia Eagles by posting photos of pregame festivities on Twitter. It also promoted its new PJM Now mobile app for tracking the load curve and LMPs in real time during the game.
FOLSOM, Calif. — Current flashpoints over grid reliability, market outcomes and ratepayer costs were on full display last week at a CAISO forum to discuss how the grid operator should overhaul its backstop procurement policies.
Representatives of generators, power traders and the California Public Utilities Commission are raising questions about the scope of an overhaul CAISO outlined in a straw proposal for its reliability-must-run (RMR) and capacity procurement mechanism (CPM) programs. While the ISO is saying changes for 2019 will only address must-offer requirements, most stakeholders contend it should move more quickly to make broader changes.
The ISO is in Phase 1 of the 2018 “RPM/CPM” initiative, saying it needs to get certain changes in place quickly before more fundamental changes are made in a future Phase 2. (See CAISO Floats Reliability Programs Revamp.) Phase 2 will include development of a cohesive RMR/CPM framework and a possible merging of the programs.
CAISO has already filed with FERC a set of updates to CPM that was approved by the Board of Governors in November. (See Board Decisions Highlight CAISO Market Problems.) The ISO’s Keith Johnson said that set of changes will not be modified in the current process but will be informed by it.
“We are not changing the filing as a result of this process,” Johnson said. CAISO’s filing of the CPM changes at FERC is due to be approved later this year, when the new package of enhancements will still be in the proposal stage.
But some at the forum pushed back at Johnson, saying that there seems to be more fundamental issues with the RMR programs, which are unpopular in the market. Two developing debates are whether RMR and CPM units should have a must-offer requirement, and whether settlement terms requiring a broad look at CPM have been triggered.
“We would agree that perhaps there are some things that should be addressed,” Johnson said as forum participants raised various issues, adding that they could consist of clarifications or more substantial changes. He pointed out that the current RMR provisions took years to develop. “I can imagine we will get all kinds of comments as to where we should take this initiative.”
The RMR and CPM have different designs and provisions and are used to keep generators online that want to retire but are still needed for reliability. Misalignments between RMR, CPM and the CPUC’s resource adequacy (RA) programs are creating reliability gaps that are costing consumers and creating tensions in the market.
But utilities such as Pacific Gas and Electric object to the hastily forged RMR agreements and their increasing usage. The ISO signed up 687 MW of Calpine generation to RMRs in 2017, including the 593-MW Metcalf Energy Center and the Yuba City and Feather River gas plants, each with 47 MW of capacity.
CPUC Staff, WPTF Disagree on Must-Offer
The ISO has proposed that Phase 1 explore whether resources under both of the RMR designations — condition 1 and condition 2 — be subject to a must-offer requirement. CAISO’s Department of Market Monitoring has recommended the measure because the condition 2 units are kept online by ratepayers but only used in certain hours.
During the forum, Resero Consulting’s Carrie Bentley, representing the Western Power Trading Forum (WPTF) debated with CPUC staff member Michele Kito over whether generators being paid to supply capacity should be subject to a must-offer obligation in the energy market. WPTF argues that the payments drive down LMPs, reducing incentives to build new generation or keep existing plants online, while the CPUC contends that units kept online 24/7 by ratepayers should be utilized more.
Bentley told RTO Insider that “WPTF believes that requiring 24/7 at-cost offers into the energy market is a means of subsidizing the fixed costs of the RMR resource on the backs on other generators. Forcing in at-cost energy into a market setting will unnecessarily distort prices downward in an already struggling ancillary service and energy market.”
Settlement Provisions Triggered?
Kito also contended that recent actions by CAISO had triggered a provision in a 2014 CPM settlement agreement that requires the ISO to open a stakeholder process to ensure that load-serving entities are not relying on the CPM as a means to meet RA obligations. Section 7 of that agreement stipulates the ISO will open the process “with the first occurrence of use of CPM by an LSE for either an annual or monthly LSE deficiency to meet 50% or more of the LSE’s RA obligation for the annual or monthly period.”
It wasn’t immediately clear what LSE Kito was referring to, and she did not return a follow up email. CAISO in November announced 2018 CPM designations for 1,055 MW of capacity in the PG&E and San Diego Gas & Electric areas. In November, CAISO said LSEs were about 2,000 MW short of local RA requirements for 2018. (See California Utilities Short on Local RA Capacity.)
“I didn’t realize that the conditions of the settlement had been triggered, at least arguably,” said Mark Smith, Calpine vice president of regulatory affairs. He told Johnson that “the scope of Phase 2 could be dramatically larger than what you have said here.”
Smith added that “the whole structure is in question. We have a clean slate, I think is what I’m hearing could occur here.”
PG&E representative Peter Griffiths asked whether the changes in the RMR process are in the scope of Phase 1, adding that he would be “concerned” if they aren’t.
“The history that the ISO has with the latest RMRs leaves a lot to be desired,” Griffiths said, noting that the process could be changed without changing the ISO’s Tariff. “If it is not going to be discussed in this stakeholder process, I would like to know that, because there are other grounds by which the process could be changed.”
Throughout the forum, Johnson advised that the scope of Phase 1 will be limited and will apply to new RMR units as of Jan. 1, 2019. The ISO is taking comments on the straw proposal through Feb. 20 and hoping for approval of Phase 1 by the board in May.
MISO says it saved its members upward of $3 billion last year, but some stakeholders are questioning whether the RTO is overstating some of the benefits it provides.
The grid operator last week released a 2017 Value Proposition study showing that its members reaped net benefits ranging from $3 billion to $3.7 billion over the year, after accounting for the RTO’s $278 million in operating costs.
MISO estimates overall benefits increased by $366 million, or 12%, when compared to 2016, when the benefit ranged from $2.6 billion to $3.3 billion.
“Again in 2017, our value proposition demonstrates the value members receive through improved reliability, market efficiencies and footprint and resource diversity,” CEO John Bear said in a statement.
During a Jan. 31 special conference call, RTO staff said the value propositions represent a range of savings because of the many variables in estimating total savings.
“An exact benefit for each of these would be extremely difficult to pinpoint,” business adviser Leonard Ashley said. The RTO excludes savings that are difficult to quantify, including energy price transparency and seams management efforts with other balancing authorities.
MISO estimates that it has provided about $20.8 billion worth of cumulative net benefits since 2007.
“Our work helps members evaluate the impact of environmental regulations, improve coordination with neighboring systems and develop new products and services to adjust to a transitioning grid,” said Wayne Schug, vice president of strategy and business development.
Ashley said the MISO South region experienced “meaningful benefit” throughout 2017, with RTO membership providing Entergy and other generators anywhere from $800 million to $900 million, accounting for $67 million in region-specific operating costs. South’s benefit increased $60 million, or 3%, over the previous year, according to MISO.
Ashley said those amounts are better than MISO’s 2013 projections, prepared when Entergy was in the process of integrating into the RTO.
Indiana Utility Regulatory Commission staffer Dave Johnston asked if MISO has ever performed a study evaluating the administrative costs for Midwest members since the addition of South. He said he remembered the RTO promising to reduce costs for its Midwest membership during a 2011 meeting. Staff responded that they might conduct more research to isolate those costs.
Show Me the Benefits
MISO attempted to break down exactly what factors contributed to the $3 billion-plus in benefits.
In terms of increased transmission availability and reliability, the RTO estimated it saved its membership $234 million to $261 million last year through avoidance of blackouts. Each likely saved megawatt was valued between $11,000 and $13,000.
MISO touted that its centralized dispatch system and modeling software resulted in a cost savings between $229 million and $259 million from improved unit commitment among the RTO’s 30 balancing authorities.
Use of the RTO’s ancillary service market reduced regulation needs by 1,162 MW, resulting in a $53 million to $58 million in savings. Ashley said each single megawatt decrease equated to about $40,000 in savings.
MISO also said its control of spinning reserves saved local balancing authorities $25 million to $27 million, compared with what BAs would have spent carrying their own reserves. Ashley said the use of spinning reserves resulted in a 530-MW reduction, with each megawatt worth $45,000 to $50,000 in production costs.
Northern Indiana Public Service Co.’s Bill SeDoris asked if MISO might be inflating the benefit of centralized spinning and contingency reserves, as many local balancing authorities had already engaged one another in a reserve sharing group prior to MISO’s creation.
Ashley said MISO could look into that, but he warned it is often difficult to unearth statistics on such collaborative efforts among utilities before the RTO’s creation.
“A footnote on the facts of life before MISO would be appreciated, so it doesn’t look like you’re trying to take credit for something you shouldn’t,” Indianapolis Power and Light’s Lin Franks added.
MISO also monetized a wind integration benefit, derived from its studies to model and pinpoint the most economic placement of wind generation to meet state renewable goals. The RTO said its economic studies avoided the construction of 9,300 MW of excess wind generation, preventing $348 million to $413 million in additional spending.
The RTO also estimated it saved members about $104 million to $132 million in compliance work throughout 2017 based on the average compliance needs for its small, medium and large generators. MISO keeps pace with about 4,000 Tariff requirements and 1,000 NERC requirements.
Customized Energy Solutions’ Ted Kuhn asked MISO to consider balancing those compliance cost savings with the money and man-hours member companies spend to attend stakeholder meetings and follow the RTO’s FERC filings. Kuhn said several members have hired dedicated employees to monitor and report on MISO’s activities and projects.
“We do have a cost of engagement,” Franks said. “You might want to talk with stakeholders to get an idea of how much is spent. … In our case, we actually hired people.”
Footprint Diversity
MISO said the single biggest financial benefit from membership stems from the RTO’s footprint diversity, which enables load-serving entities to carry just enough supply to meet its peak one-day-in-10 standard, instead of the peak estimates for each balancing area, saving customers $2 billion to $2.5 billion in avoided costs for building new generation.
MISO illustrates its footprint diversity benefit | MISO
Using the avoided costs of building an average combustion generator, MISO valued each avoided megawatt at $13,200 to $15,200. If LSEs went it alone, MISO estimated that they would have to carry an average 22.15% planning reserve margin instead of the 15.8% requirement the RTO used in 2017.
But some stakeholders again asked if MISO’s footprint benefit was based on the assumption that each utility would function as a complete island, rather than considering the pre-MISO tendency to share resources. Wisconsin Public Service’s Chris Plante said that prior to MISO’s formation, some utilities created planning reserve sharing programs to create some measure of peaking diversity.
MISO also estimated $135 million to $142 million in benefits for members through generator availability improvements in a networked system versus LSEs going it alone, based on the value of deferred generation construction. The RTO said last year it delayed the need for 882 MW of new capacity.
Franks asked if MISO’s estimates accounted for the RTO’s more nuanced dispatch method, which calls for increased stops and starts that increase wear on generators — and for the monetary penalties that unit owners incur for not responding to dispatch instruction.
“There are some downsides to this increased performance. We’ve always been ready to provide generation. With this so-called generator availability improvement comes some wear and tear on the generator,” Franks said.
MISO staff promised to consider factoring maintenance costs and penalties into the benefit calculation.
Finally, MISO said its demand response management efforts yielded anywhere from $97 million to $163 million in savings.
MISO’s Board of Directors met via conference call Friday to grant belated approval of the RTO’s second competitive transmission project, the only one in the 2017 Transmission Expansion Plan.
The board voted unanimously during a five-minute conference call to approve the 500-kV Hartburg-Sabine project, MISO’s second-ever competitively bid transmission project and the first such project to include a substation. The $130 million line is intended to alleviate constraints in MISO South’s West of the Atchafalaya Basin load pocket area bridging Texas and Louisiana. MISO has added two new staff members to oversee the competitive process behind the project and will send a request for proposals on Tuesday, leaving the bidding window open until late July. MISO plans to announce a developer no later than Jan. 2, 2019.
New WOTAB Project | MISO
Board Chairman Michael Curran said the line is on track to be “a very worthy project.”
Vice President of System Planning Jennifer Curran said the project will provide better than a 1.25 benefit ratio “in a highly congested area.”
Although it’s technically part of MTEP 17, approval of the project was delayed because of stakeholders’ concerns over the cost estimate and a late Tariff change to separate Texas and Louisiana into their own zones for cost allocation.
In November, regulators from both states asked MISO to create the separate zones for the two states to allow for a more specific cost allocation of market efficiency projects. All of the 353 other MTEP 17 projects were approved by the board in early December. (See MISO Board Approves $2.6B Transmission Spending Package.)
FERC approved MISO’s Tariff change to separate the zones last week. In a Jan. 29 order (ER18-364), the commission said the creation of zones based on state boundaries is just and reasonable, overriding East Texas Electric Cooperative’s arguments that MISO didn’t give enough notice to stakeholders to comment on the filing and that its cost estimates were inadequate.
The commission said the state-divided zones result in “an allocation of costs that is at least roughly commensurate with the benefits of market efficiency projects” and make “the adjusted production cost savings analysis more granular and arguably increases the precision with which beneficiaries are identified and costs are thus allocated.”
New Hampshire officials voted unanimously Thursday to reject Eversource Energy’s Northern Pass transmission project, stymying the company’s effort to deliver 1,090 MW of hydropower to Massachusetts.
The rejection comes just a week after New Hampshire’s southern neighbor awarded Eversource and Hydro-Québec a contract to deliver 9.45 TWh of renewably energy each year via Northern Pass. The project was the only winner in the highly anticipated solicitation. (See Northern Pass Cleans up in Mass. RFP.)
| Northern Pass
New Hampshire’s Site Evaluation Committee voted 7-0 after a three-day hearing to reject Northern Pass after expressing concerns that the 192-mile HVDC line would have negative impact on property values, tourism and land use, the Concord Monitor reported. However, committee members acknowledged the $1.6 billion project would boost tax revenues, reduce electric rates and create jobs in the communities along the corridor, the paper said.
“At a minimum, it appears today’s development requires re-evaluation of the selection of Northern Pass,” said Chloe Gotsis, a spokeswoman for Massachusetts Attorney General Maura Healey, the Associated Press reported. “The attorney general’s office remains committed to an open and transparent review and we will be following this closely.”
The final decision, which came earlier than expected, is likely to spur an appeal from Eversource, which said it was “shocked and outraged” at the outcome of the yearslong process.
“The process failed to comply with New Hampshire law and did not reflect the substantial evidence on the record,” the company said in a statement. “As a result, the most viable near-term solution to the region’s energy challenges, as well as $3 billion of N.H. job, tax and other benefits, are now in jeopardy.”
Eversource said it would seek reconsideration of the decision and review other options for continuing the project.
The International Brotherhood of Electrical Workers Local 104 “decried” the decision and said it “looked forward” to working with Eversource to advance the project.
“Today’s actions by the N.H. Site Evaluation Committee to deny a permit to Northern Pass are a major disappointment to the working families of New England. After years of collecting evidence and data, in the end it appears that the SEC made their decision based on special interest opinions and not the facts,” the IBEW said in a statement.
Northern Pass Route Map | Northern Pass
Project opponents lauded the committee’s decision.
“The people of New Hampshire rejected the unreasonable burden of international transmission lines proposed by Eversource and Hydro-Québec,” said Catherine Corkery, chapter director of the New Hampshire Sierra Club. “The Site Evaluation Committee heard our objections to Northern Pass because it would ruin our landscapes, small towns and forests.”
“Northern Pass has bullied its way through this process, and today’s decision says loud and clear that the people of New Hampshire won’t stand for it,” Conservation Law Foundation attorney Melissa Birchard said. “The committee served us well. It heard the overwhelming opposition of towns and communities, and it rejected Northern Pass’s false claims that New Hampshire’s properties, tourism industry and treasured resources would be unmarred by this proposal.”
In commending the SEC decision, RENEW Northeast urged Massachusetts “to reconsider the dozens of other bids to bring new renewable generation to the region.” The nonprofit said Northern Pass and its associated energy from Hydro-Québec would have cost state ratepayers $500 million annually for 20 years.
“Despite this high cost, it would only bring energy from old generation rather than from new renewable resources that can enable Massachusetts to achieve its required greenhouse gas emissions reductions,” the group said.
OKLAHOMA CITY — SPP CEO Nick Brown told the RTO’s Board of Directors and Members Committee on Tuesday that NERC is proposing it replace SERC Reliability Corp. as the compliance authority for the RTO’s registered functions for two years following the termination of its Regional Entity.
NERC’s Board of Trustees will vote on the plan to oversee the RTO at its Feb. 8 meeting in Fort Lauderdale, Fla.
Brown said he, Chairman Jim Eckelberger, Directors Larry Altenbaumer and Bruce Scherr, and SPP senior staff recently visited with NERC senior officials to share their thoughts about the arrangement.
“We expressed our concerns and our thinking about this,” said Brown, declining to offer further details. “The meeting was informative, with information hopefully gleaned from both sides.”
SERC has had responsibility for compliance monitoring and enforcement of the RTO’s registered functions since 2010.
According to the proposed agreement, NERC will act as SPP’s compliance enforcement authority (CEA) to “facilitate the transition.” It’s a function the agency has performed before on “multiple occasions,” a NERC spokesperson said.
SPP had sought to have ReliabilityFirst take over from SERC. “Based on our due diligence, we believe ReliabilityFirst is best positioned to perform our audits going forward,” SPP spokesman Derek Wingfield said Thursday. “We’ll continue to voice our concerns to NERC through standard channels and are confident they will be welcomed.”
The RTO announced in July it had reached an agreement with NERC to dissolve the SPP RE, ending a reliability oversight role that had been a source of concern at the reliability organization and FERC. The RE is responsible for auditing and enforcing NERC reliability rules for 120 registered entities in three balancing authorities: SPP, Southwestern Power Administration and parts of MISO.
Since then, SPP has worked with NERC to help its registered entities find a new RE. NERC has placed the entities in either the Midwest Reliability Organization (MRO) or SERC, both of which are adding staff — some from the SPP RE — to handle their added responsibilities. (See NERC Assigns SPP RE Registered Entities to MRO, SERC.)
Authorizing NERC management to sign the termination agreement with SPP for an amended and restated delegation agreement that includes the agency’s CEA role;
Approving the proposed reassignment of the SPP RE’s registered entities to MRO and SERC; and
Approving proposed amendments to regional delegation agreements with MRO and SERC to reflect their new geographic boundaries.
Following the votes and assumed approvals by the MRO and SERC boards, NERC will file for acceptance with FERC. The agency says it expects to file “as soon as practicable” and no later than June 30.
That timing concerned Dave Christiano, chair of the SPP RE’s Trustees.
“We don’t understand why it should possibly take that long. If we go past that date, the viability of the organization is at stake,” he said. “At some point, we will no longer be able to exist and do what we’re supposed to do in our own delegated agreement. We’re going to be lobbying strongly … to hopefully push this along as soon as we can.”
Brown and Christiano said the RE’s staff are down to 20 employees, a 25% drop. The two most recent departures landed with SERC.
In a Jan. 25 email to its members, SPP RE President Ron Ciesiel said he didn’t have a timeline for how long FERC would deliberate, but that approval “could take through the end of 2018.” He said the RE has created a “strenuous set of staff goals and metrics” to keep employees focused.
The proposed termination agreement requires SPP to:
Transition relevant files and documents to transferee REs.
Submit to NERC a breakdown of wind-down and dissolution costs; unaudited quarterly financial reports for the periods preceding the termination’s effective date; and a reconciliation of actual expenses with budgeted expenses after the termination date.
Transfer to the transferee REs any penalty payments, excess statutory assessments and reserves related to the SPP RE that will not be used for wind-down and dissolution of its delegated authority.
Under the agreement, NERC would:
Assist with the transition of compliance monitoring and enforcement processes to each transferee RE.
Indemnify and hold harmless SPP from certain claims and liabilities.
CARMEL, Ind. — Midwest gas-fired generators have made incremental improvements to ensure fuel supply over the past year, MISO stakeholders learned Thursday.
At a Feb. 1 Reliability Subcommittee meeting, MISO Electric-Gas Operations Coordinator Phil Van Schaack said the RTO’s winter fuel survey shows generators made “modest improvements to fuel assurance” this winter when compared to statistics from the 2016/17 annual survey.
The report indicates that 44% of MISO’s 70.7 GW in natural gas capacity have either access to firm transportation or dual-fuel capability, up from the 40% reported last year.
The RTO’s remaining capacity either relies on a combination of firm transport and interruptible transport (33%) or all interruptible transport (8%). MISO also reported that 17.8 GW of natural gas plants holding firm transportation contracts say their firm transport is shared across multiple generators within their resource portfolios, a small decrease from last year’s results.
Van Schaack also said the number of generators subscribing to flexible pipeline services increased moderately over the last year.
More needs to be done in testing dual-fuel capability ahead of time, he said. Thirty percent of MISO’s dual-fuel generators have tested their backup fuel in the last three months, while 50% have operated on backup fuel within the last year.
Gas-fired facilities with dual-fuel capability account for just under 18 GW (25%) of the gas capacity in the MISO footprint. Approximately 63 GW of MISO’s gas-fired capacity answered the 2017 survey, representing 89% of the capacity registered in the RTO’s commercial model. MISO’s total natural gas capacity accounts for 41% of its total capacity.
Van Shaack said independent power producers and qualifying facilities predominately located in MISO South comprised the remaining 7.5 GW of natural gas generation that did not respond to the survey.
MISO credited its improved gas-electric communication, including the survey, for helping the RTO reliably navigate the cold snap that swept most of MISO in early January. (See MISO Breaks down Recent Cold Snap.) The survey specifically improved situational awareness during the extreme weather, the RTO said.
The survey also revealed that 58% of responding gas-fired generation owners are comfortable that their current pipeline service offerings meet their generation needs, with 11% saying they are dissatisfied and another 18% admitting they could use additional service.
WEC Energy Group’s 2017 earnings surged 28% to $1.2 billion, boosted by a late-year cold snap and federal tax cuts.
The frigid temperatures “particularly between Christmas and New Year, added 2 cents/share, and drove us above the top end of our guidance range,” CEO Gale Klappa said during a Jan. 31 earnings call. The company earned $3.79/share.
WEC’s strong performance was key in electronics manufacturer Foxconn’s decision to connect a massive proposed plant to the southeastern Wisconsin grid, Klappa said.
“Our track record of reliability and competitive rates was a factor in the decision by Foxconn Technology Group to invest $10 billion in a high-tech manufacturing campus here in Wisconsin. This is one of the largest economic development projects in American history,” he said.
MISO is expected to render a decision by March on American Transmission Co.’s expedited request to build the interconnection project to link Foxconn’s manufacturing plant to WEC subsidiary We Energies’ supply. The RTO found the project would have a low economic benefit over the next 20 years, making it an unlikely candidate for wider cost allocation. (See MISO Seeks Stakeholder Input on Foxconn Decision.)
Although Milwaukee officials are questioning the impact of the project on residential bills, the Wisconsin Public Service Commission last year approved a settlement that will maintain a flat base rate for WEC’s utilities for the next two years.
“In total, this will keep base rates flat for four consecutive years and essentially gives us our customers’ price certainty through 2019,” Klappa said.
The project is slated to go in service in December 2019.
Klappa also said WEC will continue work on its Peoples Gas subsidiary’s system modernization plan in Chicago, replacing 2,000 miles of at-risk mains and upgrading 300,000 customer services lines over the next three decades, possibly requiring excavation of half the city’s streets. Illinois regulators last month ended a two-year investigation into the $6.8 billion project, which had been criticized for runaway costs and poor management.
WEC Energy Group service map | WEC Energy Group
“This program is literally critical to providing our Chicago customers with a natural gas delivery network as modern, safe and reliable,” Klappa said. “For many years to come, we will need to replace outdated natural gas piping — some of which was installed more than a century ago and is rusting — with state-of-the-art materials.” He added that WEC is working with the Illinois Commerce Commission on a “plan to flow savings from the new federal tax law back to customers in Chicago.”
Klappa also said subsidiary Minnesota Energy Resources will work the impact of tax reform into a pending rate case before the Minnesota Public Utilities Commission, which seeks to raise natural gas base rates by $12.6 million, or approximately 5%. The PUC has approved an interim rate increase at $9.5 million (3.8%) since late November, and a final decision is expected by the end of the year.
WEC’s 2017 results include earnings from recurring operations of $3.14/share and the net impact of a one-time gain of 65 cents/share from December’s federal tax reform law. This compares to 2016’s year-end earnings of $2.96/share.
For the fourth quarter alone, WEC recorded net income of $432.6 million ($1.36/share), compared to earnings of $194.4 million ($0.61/share) for the fourth quarter of 2016.
California utilities and other parties say they have reached a new settlement over the costs of shutting down the San Onofre nuclear power plant, replacing a contested 2014 agreement.
Southern California Edison and San Diego Gas & Electric, co-owners of the plant, said Tuesday that they submitted the agreement for approval by the California Public Utilities Commission, which in December 2016 ordered renegotiations after it came to light that former commission President Michael Peevey had engaged in undisclosed ex parte communications with SCE. The original settlement stuck ratepayers with 70% of the costs related to the early closure of the plant. (See CPUC Orders Renegotiation of San Onofre Settlement.)
The San Onofre Nuclear Power Plant was retired in 2013
The settlement stipulates that the two utilities would cease rate recovery of $775 million in costs related to San Onofre. It also reduces the regulatory asset value used to calculate recovery by $72 million by applying funds from litigation between the utility and the U.S. Department of Energy over fuel disposal responsibilities. Depending on the commission’s decision on the reduction in asset value, rate recovery would cease on either Dec. 19, 2017, or April 21, 2018.
SCE would retain amounts collected under the prior agreement before the cessation of rate recovery and will keep $47 million from arbitration with Mitsubishi Heavy Industries over the plant’s faulty generators. The utility would also retain the right to keep proceeds from selling nuclear fuel, which “may be significant.”
The proposed agreement also reduces from $25 million to $12.5 million the amount the utilities would spend to fund greenhouse gas reduction programs. SCE said the total after-tax earnings charge from the settlement will be $448 million.
“SCE and plant co-owner, SDG&E, have already returned more than $2 billion to customers under the 2014 settlement, which ensured that customers did not pay for the faulty steam generators, which prompted the closure of San Onofre, from the time this equipment failed,” SCE said.
The San Onofre Nuclear Power Plant control room in 1968
Elizabeth Echols, director of California’s Office of Ratepayer Advocates, said: “This deal saves SCE and SDG&E customers hundreds of millions of dollars over the next several years. ORA and others worked hard to put together a strong case and succeeded. Now customers won’t end up unfairly paying for many of the costs associated with the [plant’s] premature failure.”
Other parties to the settlement include the Alliance for Nuclear Responsibility, the California Large Energy Consumers Association, California State University, Citizens Oversight, the Coalition of California Utility Employees, the Direct Access Customer Coalition, ratepayer Ruth Henricks, The Utility Reform Network and Women’s Energy Matters.
The D.C. Circuit Court of Appeals on Tuesday refused to overturn FERC’s decision to require Entergy Arkansas (EAI) to make $11 million in retroactive payments to its affiliate companies.
The Arkansas Public Service Commission last month appealed FERC’s rejection of its request to exclude EAI from making the backdated 2005 “bandwidth” payments stemming from Entergy’s system operating agreement, which EAI exited in 2013 (EL01-88-013). (See Ark. Regulators Contest Entergy Bandwidth Payments.)
| Entergy
The state regulator contended the agreement made no provision for assessing payments after withdrawal, which meant the utility had no continuing obligation to its sister companies.
A three-judge panel for the D.C. Circuit disagreed with the PSC’s argument, saying EAI’s withdrawal does not mean it “extinguished its obligation to make incurred bandwidth payments” (No. 16-1193).
The court said contract law principles “support FERC’s conclusion that a party’s accrued contractual obligations continue beyond its withdrawal from a contract.” It cited commercial code that provides that “all obligations which are still executory on both sides are discharged” upon a contract’s termination, but “any right based on prior … performance” — that is, any accrued obligation — “survives.”
The PSC “points to no case or authority suggesting otherwise,” the court said.
The judges also disagreed with FERC’s contention that it should refrain from deciding the case because it “lacks the finality and/or ripeness necessary for judicial review.” They said FERC’s earlier decision consummated the agency’s decision-making process and determined EAI’s obligations.
Delaying consideration of EAI’s liability “would not ‘permit better review of the issues,’” the court said, “because the issues on review largely revolve around contract interpretation uninfluenced by future events.”
The ruling was issued by Chief Judge Merrick Garland and Circuit Judges Sri Srinivasan and Patricia Millett, who heard oral arguments in December.
The Arkansas commission is evaluating the ruling and considering “the options we may have,” Executive Director John Bethel told RTO Insider. “We want to make sure the Arkansas ratepayers are fairly treated.”
Under the Entergy system agreement, which expired in 2016, low-cost operating companies made annual payments to the system’s highest-cost company. The “bandwidth” remedy was used to ensure that production costs for Entergy’s five utilities were no more than 11% above or below the system average.
