Entergy reported third-quarter earnings of $2.16/share Tuesday, beating analyst expectations, but its stock continued a months-long decline.
Despite beating Wall Street predictions of $1.95/share, according to Zacks Investment Research, Entergy shares have lost about $2.48/share since Monday’s close, a 3.3% drop. Its fall below $72/share continued its slide since setting a 52-week high of $82.08 in early July.
Nine of 11 analysts tracked by Zacks rate Entergy stock as a hold, with one rating it a strong buy and another a strong sell.
After the earnings report, Morgan Stanley downgraded Entergy to underweight, citing weak sales and risks to earnings from the potential disallowance of nuclear costs. It set a $68 price target.
Logo on Entergy Building in New Orleans, La. | photonews247.com
Entergy has announced it plans to shutter its Vermont Yankee (already being decommissioned) and Pilgrim (in 2019) nuclear plants in New England, and the company is attempting to sell its James A. FitzPatrick unit in New York in Exelon. Costs related to the closures were reflected in the corporation’s 2015 earnings, Entergy CEO Leo Denault said during a conference call with industry analysts Tuesday.
Denault said the company’s Arkansas and New Orleans operating companies have made filings with state regulators seeking approval to deploy advanced metering infrastructure (AMI) as early as 2019. Denault said AMI “will lay the foundation for an integrated energy network.”
Theo Bunting, Entergy’s group president of utility operations, told analysts the corporation has projected its total AMI investment at $900 million “on a system basis,” and includes development of the technology’s backbone.
“As you go through the filings, you will see that there were some costs we’re asking to defer that will get fully incurred prior to the full functionality of the meters themselves,” Bunting said. “We also believe that infrastructure is useful for other systems as well. So I think our perspective is the cost is consistent with what we’ve seen in implementations across the country.”
“We continue to make those modernizing investments that will lower production cost [and] provide significant benefits to our customers,” said Denault, adding that the corporation’s financial outlook reflects “our prudent decision to position the nuclear fleet for sustained operational excellence.”
Denault also told analysts the company has 48 projects “totaling roughly” $480 million up for consideration in MISO’s 2016 Transmission Expansion Plan (MTEP). Entergy has submitted another $700 million of proposed projects for MTEP 2017.
“We will work with MISO on the selection process for those proposals over the course of the next year,” Denault said.
The company says it expects earnings of $6.60 to 7.40/share for the year.
FERC granted a Maryland solar developer’s request to reinstate its position in PJM’s interconnection queue, which the company lost because of delays in obtaining state approval (ER16-2645).
Dan’s Mountain Solar initiated the interconnection review process in 2014 to connect its 18.36-MW project in Allegany County to Potomac Edison’s 138-kV Frostburg-Ridgeley line.
The developer obtained its facilities study from PJM in December 2015, triggering a 60-day countdown for signing the interconnection service agreement (ISA). PJM later extended the ISA deadline to June 2, 2016.
But the developer didn’t receive its Certificate of Public Convenience and Necessity from the Maryland Public Service Commission — a requirement for signing the ISA — until July 11, two-and-a-half months after the state had promised a decision and just more than a month after the project was automatically withdrawn from the PJM queue on June 7.
Because transmission upgrade costs are determined by a unit’s interconnection position, PJM intervened to note that reinstating Dan’s Mountain’s queue position could disadvantage interconnection applications that have been filed in the interim. But in a Sept. 21 email to the developer, PJM acknowledged that as of that date, no other projects would be negatively impacted by its reinstatement.
FERC granted the developer’s request for a waiver of the deadline following an expedited review, saying “it appears this waiver will not harm third parties.”
“Although PJM’s Oct. 6, 2016, comments assert that the potential for harm to third parties increases as time passes, PJM did not indicate that harm is imminent,” the commission said in its Oct. 25 order.
The waiver allows Dan’s Mountain to continue where it left off and avoid restarting the application process.
The Sacramento Municipal Utilities District (SMUD) will join the Western Energy Imbalance Market (EIM) in spring 2019 at the earliest, according to the head of the joint powers agency of which the utility is the largest member.
Shetler | United Way
“As you might guess, this is a very intense technical project,” Jim Shetler, general manager of the Balancing Authority of Northern California (BANC), told RTO Insider.
The four utilities that have joined the EIM to date have required 18 to 24 months to begin operating in the EIM after signing an implementation agreement with CAISO, the market’s operator.
SMUD will likely sign such an agreement early next year, Shetler said. “We’re just starting to meet with the ISO to lay out project plans.”
The utility announced its intention to join the EIM on Oct. 21, citing the benefits of increased renewable integration, potentially reduced reliance on gas-fired generation and lower operational costs. (See Sacramento Utility to Join EIM; Other BANC Members May Follow.)
SMUD would be a first municipal utility to sign up for the market — a status that could potentially complicate its efforts to join. Municipal utilities are not subject to FERC jurisdiction — but the EIM is. (See Co-ops, MISO, SPP Urge FERC Restraint with Nonpublic Utilities.)
“With FERC oversight, we’re trying to understand what that would mean,” Shetler said. “SMUD has an open access transmission tariff that was approved by its board, but not by FERC.”
SMUD already operates under an agreement that enables the utility to bid power into CAISO through a single hub in which one proxy price is selected to represent all connection points between the two areas.
A joint study conducted by BANC and the Western Area Power Administration estimated that SMUD would gain $2.8 million in yearly net benefits from transacting in the market — a figure that nets out an estimated $6.7 million in implementation fees and $2.6 million in annual operations costs.
Shetler said that SMUD’s annual benefit could increase to about $5 million after five years, once the utility has paid down startup costs.
“It’s a big number, but a small number compared with their energy resource portfolio,” Shetler said. The real value will come in integrating the increased number of variable resources needed to meet California’s 50% by 2030 renewable energy mandate, he noted.
Sacramento Municipal Utility District headquarters | SMUD
SMUD would be breaking ground for possible future EIM participation by BANC’s other municipal utility members, including Modesto Irrigation District and the cities of Redding and Roseville.
Two other members — the city of Shasta Lake and Trinity Public Utilities District — own no generating resources and would therefore derive no benefit from joining the market, Shetler said. Trinity, a “full requirements” customer of WAPA, receives all of its energy from the federal agency.
Could other BANC members piggy-back on SMUD’s efforts and reduce their costs to join the EIM?
“We’re hoping that’s the case,” Shetler said. “We think there is some scale there.
“Not that it would be on the backs of SMUD or its ratepayers,” he added.
Established in 2011, BANC is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordinating Council. The agency is responsible for balancing load among its members, as well as coordinating system operations with neighboring balancing areas.
BANC contracts with SMUD to perform day-to-day balancing functions.
The BANC-WAPA study spelling out EIM benefits is slated to be released to the public in late November.
COLUMBUS, Ohio — More than 150 regulators, PJM officials and stakeholders gathered for last week’s annual meeting of the Organization of PJM States Inc. Here’s some of what we heard.
American Public Power Association CEO Sue Kelly, who appeared on a panel on PJM’s Capacity Performance model with Independent Market Monitor Joe Bowring and RTO officials, Calpine and two utilities, noted that it was her fourth such appearance before OPSI. As the lone critic of mandatory capacity markets, she joked, she felt like “the token Republican on MSNBC.”
She said the changes going on “at the end of the grid,” such as solar and demand response, are going to make CP “outmoded.” It “does not meet public-policy goals. It wasn’t designed to meet public-policy goals,” she said.
PJM General Counsel Vince Duane said there are “a whole host” of “entirely valid” public-policy goals that PJM must balance in its designs. “So it’s not a question of which policies are more important,” he said. “There’s a lot of evidence out there that we’ve done the design job very well.”
The focus needs to be on developing the flexibility for states to make policy goals while ensuring the viability of CP, he said.
He said it’s a “gross over-reading” of the Supreme Court’s Hughes v. Talen ruling to believe that any state subsidy would interfere with wholesale markets. (See Supreme Court Rejects MD Subsidy for CPV Plant.) “We can’t let the markets be used to obscure and disenfranchise the political process,” he said.
Bowring repeated his concerns that competitive markets are threatened by state-subsidized generation, as proposed in Ohio. “There is a line, and the line has to do with price formation and the integrity of the market,” he said. “To the extent that the line isn’t drawn, then the markets won’t survive.”
Kelly said the Hughes case gives states and public power utilities “a lot of options” for implementing public policies without violating federal jurisdiction. “I don’t think we should just count on that court case to squash all of this. I think it would be much better if we collectively work this out than go back to the Supreme Court three more times,” she said.
Lathrop Craig of Public Service Enterprise Group asked if a market dominated by gas, supported by renewables and experiencing major declines in coal “still makes a lot of sense” and whether a unit’s value to the market should rely on something other than its lack of emissions.
Bowring wasn’t in favor of what he described as subsidizing old units “because you don’t like where the market’s going.”
“I don’t think that’s a good idea,” he said.
Kelly raised concerns about relying too heavily on gas. “It’s kind of like dating your first husband — you have bad memories,” she said. “I have memories of gas at $3.50. I have memories of gas at $14.50. I have memories of having my contract ripped up by FERC and having to go out and replace all that.
“Things are great till they’re not great,” she added, citing concerns that fracking is causing earthquakes in Oklahoma and a rise in demand for LNG could boost gas prices.
In another panel, stakeholders discussed how state renewable portfolio standards are the largest driver of the surge in renewables on the grid. PJM’s Chantal Hendrzak outlined several initiatives the RTO is undertaking, including developing wind and solar forecasts and researching better integration of renewables and battery storage, to ensure that “when renewables come on the system, no matter how they come on the system, that we can reliably integrate them.”
The industry has moved quickly to implement states’ renewable portfolio standards, said Exelon’s Bill Berg. “Some of the lofty goals passed a few years ago now seems within reach,” he said.
As usual, the conference ended with OPSI’s Market Monitoring Advisory Committee’s meeting — an annual check-up on the status of relations between the Monitor and PJM.
Bowring said his “overall” relationship with PJM “is good,” but he noted one exception. He said the “very public” disagreement over how the Monitor interacts with PJM has resulted in “pretty tough filings back and forth on the hourly flexibility proceeding.” (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
Virginia State Corporation Commissioner Mark Christie commended Bowring, while noting that “not everyone agrees with” him.
“It is really all about making sure the markets are as efficient as possible, and we’ve always viewed the Independent Market Monitor as critical to that,” Christie said. “We certainly respect his honesty, his talent, his willingness to tell it like it is, like he sees it. Those who disagree can disagree.”
PJM Board Chairman Howard Schneider interjected, “We agree with that 100%.”
Earlier, Schneider had announced board member Susan Riley as the new chair of the Competitive Markets and Governance Committee, which oversees the engagement between PJM and the Monitor. Riley assured the audience that the committee has regular contact with Bowring, and he has unfettered access to bring issues to the board.
“Each issue that he raises is, in fact, researched with PJM, with Joe, with Joe’s staff, and we try to arrive at resolutions we can — more times than not — agree on,” she said. “The working relationship has evolved and grown over the past nine years, and I would say from where I sit that it’s working very well right now.”
Bowring agreed.
American Municipal Power’s Ed Tatum, who asked the only question during the brief meeting, appreciated the collegial tone. “The troubles are over. The waters are more still, and that’s good,” he said.
The length of MISO’s lone market efficiency project for 2016 will have to be extended, increasing its cost by as much as one-quarter and reducing its benefit-cost ratio.
MISO said the estimated cost of the Huntley-Wilmarth 345-kV project has jumped by $20 million from the original $81 million as a result of having to reroute the line to bypass the Mankato, Minn., area.
| MISO
MISO staff told the Oct. 19 Planning Advisory Committee meeting that the new benefit-cost ratio on the project may be as low as 1.5-to-1, down from the original 2-to-1.
MISO Senior Manager of Competitive Transmission Administration Brian Pedersen said the original line length was estimated at 38.5 miles. It’s unclear how many miles the reroute will add to the project, which is slated for completion in 2022.
Putting aside misgivings about the cost increase, a majority of PAC sectors approved a motion recommending that the 2016 Transmission Expansion Plan report proceed to the System Planning Committee of the Board of Directors for consideration. After that, the report will go before the Advisory Committee and Board of Directors for approval in December. (See MTEP 16 Proposes 394 Projects at $2.8 Billion.)
In a first round of feedback on MTEP 16, stakeholders urged MISO to competitively bid the line, despite Minnesota’s right-of-first-refusal statute, which would designate the project to incumbents Xcel and ITC.
“This is an issue we see no matter who does it,” an Xcel representative told stakeholders. “It’s still an urban area; it still needs to be addressed. This is the difference between the planning estimate and what the route actually is.”
Hwikwon Ham of the Minnesota Public Utilities Commission “strongly” urged Xcel to come before the state’s Department of Commerce — which advocates to the PUC on behalf of consumers — to discuss the change.
Steve Leovy of WPPI Energy asked why MISO had not presented a more accurate cost estimate when it initially rolled out MTEP 16.
John Lawhorn, senior director of policy and economic studies at MISO, said the RTO does “the best job it can.”
“Cost estimates and actual costs can vary, as you know, so we have variance analysis built into our Tariff,” Lawhorn said.
“We constantly hear MISO pushing openness in the process, and here it is again that we don’t have all the details. At a minimum, an MTEP report should at least present the best cost estimate possible,” said George Dawe, vice president of Duke-American Transmission Co.
However, Ham said he was pleased that Xcel came forward with the increased price before MTEP 16 is approved. “I’m happy to see this number came in ahead of time,” he said.
| MISO
The MTEP report says the Huntley-Wilmarth project will give load more access to lower-cost generation because it “completely mitigates” congestion on the Huntley-Blue Earth 161-kV line near the Iowa-Minnesota border. The line has been stressed by large amounts of wind capacity and low-cost coal generation in northern Iowa.
“Further worsening congestion is the increase in wind capacity in Iowa that is assumed over the next 15 years,” the report says. “Finally, expected coal retirements near the Minneapolis/Saint Paul area such as Sherco 1, Sherco 2 and Clay Boswell 3 tend to increase the need for power to flow from northern Iowa to the Twin Cities via the Lakefield to Wilmarth 345-kV path. As a result, for the loss of this high-voltage transmission path, the low-voltage parallel path of Huntley to Blue Earth 161-kV becomes congested.”
FERC last week eliminated the must-offer obligation in effect throughout the Western Electricity Coordinating Council region since the tail end of the California energy crisis of 2000-2001.
“In light of the passage of time and significant improvements to California’s wholesale electricity markets over that time, the must-offer requirement established for the WECC in 2001 produces little or no benefits today,” the commission wrote (EL27-16).
FERC implemented the obligation in June 2001 in response to what it called “serious market dysfunction” in California — the effort by some of the region’s generators to withhold power supplies to drive up prices in the now-defunct California Power Exchange. The rule required most generators serving California to offer all capacity not already committed under bilateral agreements into the state’s real-time market.
Last week’s order also ended a requirement that public and nonpublic utilities post a daily log of available capacity on their websites, as well as to a site hosted by the Western Systems Power Pool (WSPP).
The commission also rejected a request by the Edison Electric Institute to retroactively relieve affected industry participants of costs related to the posting requirement, instead affirming Feb. 24, 2016, as the refund effective date — days after FERC initiated a Section 206 proceeding to explore eliminating the must-offer obligation. (See FERC Likely to Eliminate Must-Offer Rule for West.)
While EEI did not specify an alternative date, it contended that the posting requirement became unduly burdensome once California’s market had undergone substantial changes and that FERC should therefore “grant such further and other relief as to the posting requirement that the commission deems necessary or appropriate.”
The must-offer and posting requirements were originally slated to expire in September 2002, but FERC subsequently extended the rules for an unspecified period of time until “long-term market-based solutions” could be fully implemented.
In eliminating the obligation, the commission cited numerous changes to California’s markets over the years, including CAISO’s development of LMP-based day-ahead and real-time energy and ancillary services markets, a day-ahead residual unit commitment process, local market power mitigation measures, reduced reliance on spot markets, and the state’s resource adequacy program.
“These market design improvements have contributed to a well-functioning CAISO market,” the commission wrote, adding that the electricity supply outlook for the West has “significantly improved.”
The commission noted that its ruling only dealt with rules stemming from the energy crisis. This was in response to Pacific Gas and Electric’s argument that termination of the obligation should not be construed as limiting the need for a must-offer requirement for resource adequacy capacity in the CAISO-run Energy Imbalance Market or new ISO transmission owners.
“We are not prejudging any future must-offer proposals related to the Energy Imbalance Market or to new transmission owners joining CAISO,” the commission affirmed.
FERC on Thursday denied Dominion Resources’ request for rehearing of an order rejecting its challenge to ISO-NE’s 2016 Forward Capacity Auction over a paperwork error that excluded capacity from its generating plant in Providence, R.I. (EL16-38-001).
Manchester Street Station | Dominion
The commission on May 2 denied most of Dominion’s February complaint about ISO-NE’s decision to block new incremental capacity from an upgrade to the company’s Manchester Street Station from participating in FCA 10 in February. The three-unit generator boosted its summer capacity by 21 MW to 477 MW.
In September 2015, ISO-NE approved the additional 21 MW for the auction. But the RTO later disqualified the additional capacity because Dominion failed to submit a “composite offer” linking the new capacity and the existing capacity at the plant.
The deadline for composite offers was Oct. 9, 2015. Dominion filed its complaint with FERC just days before the FCA in February.
The commission rejected the complaint in May, finding that the company had received adequate notice of the RTO’s filing requirements in October and November. The commission directed ISO-NE to revise its Tariff to provide greater clarity but denied Dominion’s request to resettle the auction as if the company’s additional capacity had participated.
“We are not persuaded by Dominion’s assertion that the commission erred in determining that ISO-NE did not violate its Tariff and was therefore mistaken in finding that resettlement was not required,” FERC wrote last week. “It would be contradictory to find that ISO-NE’s Tariff was unjust and unreasonable because it failed to provide notice of the filed rate, while also finding that ISO-NE violated the filed rate.”
FERC’s May order did find that ISO-NE’s tariff was “unclear regarding the process for new incremental generating capacity and existing generating capacity at the same resource to participate in the FCA.”
ISO-NE responded with proposed Tariff changes under which it would automatically match new summer incremental generating capacity with excess existing winter qualified capacity at the same resource.
But the commission ordered the RTO on Aug. 30 to further amend its Tariff to automatically match new winter incremental capacity with excess existing summer qualified capacity at the same resource. “We find that there is no reason to limit, based on season, the automatic matching of new capacity with excess existing capacity,” the commission said (ER16-2126).
ISO-NE’s second compliance filing is due by the end of October.
FERC Chairman Norman Bay announced the departure of his chief of staff, Larry Gasteiger, last week at the commission’s open meeting.
Gasteiger, whose last day was Friday, will take the role of Public Service Enterprise Group’s chief of federal regulatory policy. He worked at FERC for 19 years, including as Bay’s deputy director at the Office of Enforcement.
“I am personally grateful to Larry for the help he has given me over the years,” Bay said. He called Gasteiger “clearly one of the most important picks I had to make when I came in as the director of [Enforcement], when I was new to FERC and I was in great need of having a Sherpa.” Bay named Jamie Simler, current director of the Office of Energy Market Regulation, as Gasteiger’s replacement.
Energy Department Plans to Build Experimental Carbon Dioxide Plant
| Energy.gov
The Department of Energy is providing $80 million to build an experimental 10-MW power plant in San Antonio that will use carbon dioxide instead of steam to generate power.
Gas Technology Institute will lead the pilot project with Southwest Research Institute serving as an equal partner. General Electric’s Global Research team will also be involved.
EPA has not properly estimated job losses in the coal industry resulting from the Clean Air Act, a federal judge ruled last week.
The District Court for the Northern District of West Virginia ruled in favor of coal mining company Murray Energy, finding EPA has a “nondiscretionary duty” to track potential job losses and employment shifts from regulations written under the act.
“With specific statutory provisions like Section 321(a), Congress unmistakably intended to track and monitor the effects of the Clean Air Act and its implementing regulations on employment in order to improve the legislative and regulatory processes,” the opinion said.
Plaintiffs to Refile Lawsuit Blaming Fracking Industry for Earthquakes
Lawyers for two Oklahoma women will refile in state court a class action lawsuit that blames the fracking industry for the state’s recent spate of earthquakes.
The plaintiffs previously filed the suit in state court, but Devon Energy removed it to federal court under the Class Action Fairness Act of 2005, prompting them to agree to a voluntary dismissal.
The plaintiffs are required by law to wait one year to refile.
House Committee Investigating WAPA Security Breaches
A House of Representatives committee has asked the Western Area Power Administration to turn over documents by Nov. 1 relating to security breaches at the Liberty substation in Arizona.
The document request is part of the House Committee on Oversight and Government Reform’s investigation spurred by a July 14 Wall Street Journal article describing physical intrusions at the substation, including one in which its control room was ransacked.
There have been no arrests, and security cameras mostly weren’t working.
Interior Secretary Supports Klamath River Dam Removal
Secretary of Interior Sally Jewell sent a letter last week to FERC urging it to approve applications by PacifiCorp and Klamath River Renewal Corp. to remove four hydroelectric dams on the Klamath River.
PacifiCorp owns the dams, and Klamath River Renewal — a consortium of federal, state, tribal and local officials — wants to take ownership for the purpose of demolition.
In a measure that’s considered mostly symbolic, county voters will have the opportunity to vote on Nov. 8 as to whether the dams should be removed.
FERC last week approved a $154.8 million 2017 budget for NERC, its eight Regional Entities and the Western Interconnection Regional Advisory Body (WIRAB) (RR16-6).
The spending plan includes $54.3 million for NERC, $99.7 million for the Regional Entities and almost $760,000 for WIRAB, which was created by Western governors to advise FERC, NERC and the West’s RE, the Western Electricity Coordinating Council.
NERC’s budget will increase 3.6% over 2016, while its workforce drops to about 190 full-time equivalents.
Democrats, Republican Call for Full Disclosure of APS Election Spending
Two Democrats on November’s ballot for seats on the state’s Corporation Commission have aligned themselves with a Republican incumbent in calling for full disclosure by Arizona Public Service as to whether it spent money on the 2014 elections.
Democrats Bill Mundell and Tom Chabin called for an end to “a culture of corruption” and cited alleged personal meetings between Gary Pierce, a former commissioner, and Don Brandt, president and CEO of APS and its parent company.
APS is suing Republican incumbent Robert Burns over his position to force it to make full disclosure. Notwithstanding, Brandt’s company is supporting Burns’ bid for re-election, according to an email Brandt sent to company employees last week.
SoCalEd Proposal Addresses Corona’s Dwindling Electric Supply
Southern California Edison engineers and city officials met with Corona residents last week regarding a proposal to build 5 miles of medium-voltage power lines to address the region’s dwindling electric supply — with one area using 92% of its energy production potential last year.
The proposal calls for primarily above-ground lines, including a 66-kV transmission line carrying power to a new substation. It also includes above-ground transmission lines that would bisect the city’s center.
Construction could begin by 2019, with the lines becoming operational by 2012, according to SoCalEd’s website.
Jacumba Solar Approved to Build Solar Plant in San Diego County
Jacumba Solar last week received approval for a permit to build a 108-acre solar plant in Jacumba, near San Diego Gas & Electric’s East County Substation.
The plant will use a little more than 81,000 photovoltaic panels on roughly 2,200 fixed, tilted racks to generate 22 MW, which it will deliver to SDG&E’s substation through a 1,500-foot-long overhead transmission line, a press release from the San Diego County Board of Supervisors said.
County staff and proponents of the project said it would help the region meet state goals of producing one-half of all electricity from renewable sources by 2030 and cut greenhouse gas emissions.
San Diego, SunEdison Tentatively Extend Solar Panel Agreement
An October 2015 agreement between San Diego and SunEdison for installation of banks of solar panels at 25 sites across the city has been tentatively extended to at least April 2017, and possibly to June 2017, after the company failed to install a single panel. The original agreement called for installation of the first solar panels by last month.
SunEdison declared bankruptcy two months before it was supposed to begin construction and sought an extension for the first batch of projects. In July, city officials formally terminated the agreement’s initial five projects.
The city declined to release the new agreement, stating that it has not yet been formally approved, but it said SunEdison agreed to compensate it for opportunity costs related to the delay.
CAISO Flexible Ramping Product Delayed Until Nov. 1
FERC last week granted CAISO’s request to postpone the start date for implementing the ISO’s flexible ramping product until Nov. 1 — one month later than the original start date (ER16-2023).
CAISO last month petitioned to delay the effective date because it did not learn of the commission’s approval of the product until hours after a conference call scheduled to confirm the roll-out to market participants.
The new market mechanism is designed to improve real-time integration of the increasing amount of variable renewable energy resources coming on to the ISO’s system. The product will also be incorporated into the ISO-run Energy Imbalance Market.
UI Customers, Environmentalists Urge Distribution Rate Reduction
While The United Illuminating Co. seeks a distribution rate increase, 16 environmental and consumer groups are urging state regulators to reduce the current fixed-rate charge of $17.25/month its customers currently pay.
In a letter to the Public Utilities Regulatory Authority, the groups noted that the monthly charge is the highest of any investor-owned electric utility in New England and urged PURA to cut it by $6 to $8/month.
Distribution charges account for 27 cents of every dollar that UI customers pay for their electricity, UI spokesman Michael West said. He said the charge allows UI to provide the level of reliability its customers have come to expect.
State Senators Continue to Push For Legislation to Save Exelon Plants
State senators are continuing to look for ways to prevent Exelon from shuttering it Clinton Power Station and Quad Cities Generating Station nuclear power plants during the next two years.
Exelon lost $800 million on the two plants over the past seven years and announced it would close the plants after state lawmakers ended their spring legislative session without approving its proposed “Next Generation Energy Plan.”
Sponsors of the legislation have been negotiating with Exelon and other interested groups, and Sen. Donne Trotter, a Democrat, said he plans to use the General Assembly’s fall veto session to continue pushing legislation when lawmakers return on Nov. 15.
State regulators last week warned that the proposed $12.2 billion sale of Westar Energy to Great Plains Energy is in jeopardy if the companies don’t supply additional information regarding operational savings, and what departments or functions would remain in Topeka and for how long.
The Corporation Commission said in an order that its staff or the Citizens’ Utility Ratepayer Board could file for relief — which could include asking for dismissal of the merger application — if they maintain that the joint application does not adequately address the agency’s merger standards.
Chuck Caisley, a spokesman for GPE and Westar, said the companies were evaluating the order and are committed to closing the transaction in the spring of 2017 as planned.
Downtown Baton Rouge now has 10 electric car charging stations, and city-parish leaders hope to have 50 stations soon as part of their effort to lure green business.
Previously, the only electric car charging stations were near Louisiana State University and in south Baton Rouge.
Entergy gave a $75,000 grant for purchase and installation of the stations.
Stakeholders Clash over Proposal to Phase out Financial Incentives for Solar
LePage
A proposal to phase out financial incentives for homeowners using solar panels caused a clash of viewpoints last week at a hearing before the state’s Public Utilities Commission.
Residents and small-business owners said the proposal — which seeks to grandfather net-metering credits for current solar homeowners for 15 years and gradually reduce benefits for new solar owners over 10 years — would stifle solar energy’s growth and already is reducing the number of installations. Representatives from utilities, government and consumer affairs testified that the current financial incentives for rooftop solar hurt other ratepayers.
Last spring, the Legislature passed a compromise solar bill following a yearlong study and negotiations among stakeholders, but it was two votes shy of overriding a veto by Gov. Paul LePage.
Lincoln is purchasing its first electric car for about $22,000, along with dual plug-in electric charging stations for privately owned electric vehicles for nine downtown garages. Some of the funds will come from a state grant.
There are currently 67 electric vehicles registered in Lancaster County, but the group that spearheaded the grant hopes the new charging stations will encourage more electric car purchases.
300 Electric Vehicle Charging Stations Coming to Public Locations
Cuomo
Gov. Andrew Cuomo announced last week a five-year New York Power Authority contract for the installation of 300 electric vehicle charging stations at public locations across the state.
The agreement supports the governor’s ChargeNY Program, which aims for 3,000 charging stations online in the state by 2018.
It also is an important step in accomplishing the state’s goal to reduce greenhouse gas emissions 40% by 2030 from 1990 levels and ensure 50% of electricity consumed comes from renewable energy sources by 2030.
NYISO Report Finds Two Localized Transmission Security Reliability Needs
A new NYISO report found two localized transmission security reliability needs that will begin in 2017 — involving New York State Electric and Gas’ Oakdale 345/115-kV transformer and Long Island Power Authority’s East Garden City-Valley Stream 138-kV line — that require remedial action soon.
The ISO said in a press release that it will consider transmission plan updates from the transmission owners and then, if necessary, issue a solicitation for market-based and regulated solutions.
NYISO’s 2016 Reliability Needs Assessment report also found that the state’s bulk power system has adequate power generation resources to meet reliability needs for the next decade.
Feds Plans to Auction Gas Lease Rights for Wayne National Forest
The federal government gave notice last week that it is planning an online auction for Dec. 13 for oil and gas lease rights for Wayne National Forest, which could lead to fracking on public land.
Opponents have 30 days to file a formal protest.
The land is located in the far eastern part of the forest, where there are substantial oil and gas reserves and less opposition to energy drilling.
Commission Recommends Taxpayer-Funded Solar Incentives
The Public Utility Commission voted last week to pass a recommendation to the Legislature that it consider adopting taxpayer-funded incentives for solar energy programs that all residents can benefit from, regardless of their utility provider.
The state already has several taxpayer-funded programs intended to encourage solar energy development, but some of the incentives are scheduled to end soon. There also are a small number of ratepayer-funded programs, for which customers of specific utilities pay.
The commission noted that calculating the benefits and costs of each program is difficult because projects and customers are often eligible for more than one incentive program.
FirstEnergy Rate Case Settlements to Increase Residential Rates
FirstEnergy’s utilities filed distribution rate case settlement agreements with state regulators last week that, if approved, would result in rate increases for residential customers.
Met-Ed customers would see an average increase of 10.7%; Penelec customers 12.8%. Penn Power 10.4%; and West Penn Power 7.2%.
The state Public Utilities Commission is expected to issue final orders on the agreements and new rates on or before Jan. 26, 2017. Pursuant to the agreement, the utilities would not file for additional distribution base rate increases in the state until January 2019 at the earliest.
Dominion Required to Increase Water Monitoring at Possum Point
As Dominion Resources works to drain and consolidate five coal ash ponds at its Possum Point Power Station in Dumfries, state regulators are demanding that it install nine additional wells on the property and test water samples from monitoring wells on a biweekly basis.
Two of the nine additional wells will be monitoring wells installed near the property’s perimeter and may help detect whether groundwater from Dominion’s coal ash ponds is flowing toward nearby residential wells and contaminating drinking water.
Dominion is hoping to receive a solid waste permit so that it can move all its coal ash into one pond and bury it beneath two feet of soil.
Grassroots Effort Opposes Pipeline Extension in Eastern Panhandle
A grassroots effort is growing against a proposal by Mountaineer Gas Company of West Virginia to extend its natural gas distribution line by 56 miles in the Eastern Panhandle.
If approved by regulators, the pipeline project, slated to begin in 2018, would pass through Berkeley, Jefferson and Morgan counties, using buried lines 6 to 12 inches in diameter.
The state’s Public Service Commission has received 70 letters in opposition, said Russell J. Mokhiber, of Morgan County USA blog, who conducted an opposition meeting last week and distributed fliers saying “just say no to the gas pipeline.”
Judge to Decide Fate of Badger-Coulee Power Line Project
A La Crosse County judge will decide the fate of a 180-mile 345-kV transmission line from the La Crosse to Madison areas.
American Transmission Co. and Xcel Energy developed the Badger-Coulee Transmission Line project in 2010, and the Public Service Commission approved it in 2015.
The Town of Holland maintains that the commission did not legally approve the project — estimated to cost about $580 million — because it did not establish a need for it.
MISO announced on Friday it had changed four elements of its proposed forward capacity auction, prompting renewed calls from some stakeholders to delay a FERC filing planned for Nov. 1.
RTO officials — who described the changes as a “refinement” to a “limited set of design elements” — insisted the filing will be made as scheduled.
On an Oct. 21 Resource Adequacy Subcommittee conference call, MISO revealed it had adopted the Independent Market Monitor’s suggestion to incorporate a pivotal supplier test in the forward auction for the RTO’s retail-choice regions.
Officials also said they will include a three-year forward peak load contribution calculation and modify the design’s materiality test, congestion calculation and cost allocation.
Pivotal Supplier Test
The pivotal supplier test would allow the Monitor to identify resources inside or outside MISO’s footprint that are large enough to affect market outcomes. Suppliers identified as pivotal would be subject to the RTO’s existing physical and economic withholding provisions.
Dynegy’s Mark Volpe said that while the Monitor “should certainly suggest marketing monitoring measures,” the pivotal supplier test had not been explored in the stakeholder process and was not simply a “tweak.” He asked for a conference call with the Monitor prior to Nov. 1 to discuss the test. MISO staff said that was unlikely to happen.
Congestion Charges
Under other changes, MISO would allocate congestion charges resulting from the clearing of infeasible resources to buyers rather than sellers as originally proposed. Officials said the change was made to avoid discouraging sellers’ participation in the auction and to align the cost allocation with other FERC-approved capacity markets.
The RTO also said it will limit congestion charges in the forward auction to situations in which constraint changes lead to a less than one-day-in-five-years loss-of-load expectation. MISO’s prior draft allowed congestion charges to occur anytime a locational constraint binds and proved more restrictive under the forward auction than the prompt Planning Resource Auction. The change will maintain the relationship between the variable reliability target and the quantity of capacity procured for competitive retail demand, MISO said.
Consumers Energy’s Jeff Beattie noted that MISO’s retail-choice areas are “heavily interconnected” and said he doubted the new cost allocation would ever occur.
Jeff Bladen, executive director of MISO market services, agreed that new congestion costs would only occur under “extreme circumstances” when incremental resources are need to step in for megawatts that cannot be delivered.
“In a sense, it’s a replacement charge because the constraints modeled need to be changed,” Bladen said. He said the charge is needed because MISO “can’t guarantee feasibility three years into the future.” He noted that ISO-NE, NYISO and PJM use a similar method.
Peak Load Contribution
The addition of a peak load contribution calculation was intended to “alleviate retail customer risk from their purchase/offer obligations” in the forward auction against any PLC changes that take place in the PRA, MISO said.
Bladen said the PLC provides “equal footing between demand and supply resources that enter into the forward auction.”
Materiality Test
The materiality threshold determines whether local resource zones will be included in the forward auction. It will be used in Michigan and Wisconsin, where the zonal boundaries traverse state lines.
The original proposal would have determined materiality based on the potential impact of competitive retail demand on the systemwide LOLE and could change from year to year.
Under the revision, MISO would determine materiality based on the greater of the LOLE impact and a fixed percentage (0.5%) of the systemwide planning reserve margin requirement.
MISO said the change provides a “reasonable balance” between reliability and certainty.
Filing Delay Sought
Several stakeholders asked for a delay in the filing to better understand the latest changes.
“This congestion charge is just not clear yet,” Indianapolis Power and Light’s Ted Leffler said.
Minnesota Public Utilities Commission staffer Hwikwon Ham said he wasn’t yet comfortable with wording on the Tariff changes.
RASC Chair Gary Mathis said if the subcommittee demanded a filing delay, it would only be taken under advisement by MISO. The next scheduled meeting of the RASC will be held on Nov. 2, a day after MISO’s projected filing date.
Bladen said MISO is “very proud of how the proposal has evolved and the balance it strikes.”
“Thanks for your comments and contributions,” he said.
EPA has not properly estimated job losses in the coal industry resulting from the Clean Air Act, a federal judge ruled last week.
Secretary of Interior Sally Jewell sent a letter last week to FERC urging it to approve applications by PacifiCorp and Klamath River Renewal Corp. to remove four hydroelectric dams on the Klamath River.
A new NYISO report found two localized transmission security reliability needs that will begin in 2017 — involving New York State Electric and Gas’ Oakdale 345/115-kV transformer and Long Island Power Authority’s East Garden City-Valley Stream 138-kV line — that require remedial action soon.
The federal government gave notice last week that it is planning an online auction for Dec. 13 for oil and gas lease rights for Wayne National Forest, which could lead to fracking on public land.
The Public Utility Commission voted last week to pass a recommendation to the Legislature that it consider adopting taxpayer-funded incentives for solar energy programs that all residents can benefit from, regardless of their utility provider.
FirstEnergy’s utilities filed distribution rate case settlement agreements with state regulators last week that, if approved, would result in rate increases for residential customers.
As Dominion Resources works to drain and consolidate five coal ash ponds at its Possum Point Power Station in Dumfries, state regulators are demanding that it install nine additional wells on the property and test water samples from monitoring wells on a biweekly basis.
A grassroots effort is growing against a proposal by Mountaineer Gas Company of West Virginia to extend its natural gas distribution line by 56 miles in the Eastern Panhandle.
A La Crosse County judge will decide the fate of a 180-mile 345-kV transmission line from the La Crosse to Madison areas.