MISO and PJM will have 65 days to evaluate the impact of generator retirements under joint operating agreement language drafted to comply with a FERC directive.
The subject of a briefing at MISO’s Reliability Subcommittee meeting last week, the JOA language requires the RTOs to notify each other of retirements and exchange the most up-to-date modeling data.
The results of the retirement impact studies and possible transmission upgrades will also be shared. Projects in one RTO that have benefits or impacts in the neighboring RTO will be evaluated by the Joint Regional Planning Committee and the Interregional Planning Stakeholder Advisory Committee (IPSAC).
Alternatives to transmission upgrades will include market-to-market coordination to use external resources, as well as operating guides and procedures involving the adjacent RTO.
| MISO
In response to a complaint by Northern Indiana Public Service Co., FERC required the RTOs to file language coordinating their generator retirement studies and dispatch assumptions by Dec. 15, 2016 (EL 13-88).
The commission cited NIPSCO’s testimony that PJM used unrealistic dispatch assumptions in its study of the retirement of the Crawford and Fisk generating plants in the Commonwealth Edison territory, “which caused PJM to fail to identify required upgrades and masked potential problems within MISO, including overloads on NIPSCO’s system.” (See FERC Orders Changes to MISO-PJM Interregional Planning.)
Joe Reddoch of MISO’s System Support Resource Planning Group said MISO focused on appropriate communication between the RTOs and reviewed its existing retirement process to make sure it was still relevant.
Reddoch commented on the 65-day deadline for evaluating retirements.
“Currently, it’s more or less open-ended. We don’t necessarily have a deadline to get back to them with study results that would factor into their retirement studies,” Reddoch said.
He added that supplying such information would be more vital to PJM, which — unlike MISO — cannot force generators to stay online as must-run resources.
Reddoch said transmission projects the RTOs identify as a result of their analyses might not be detailed or polished.
“Each RTO would conduct a retirement analysis to determine the impacts to their system and possible transmission projects. We won’t necessarily have those projects defined,” he said.
Reddoch said MISO would look to PJM’s information to update its modeling information, but directly involving PJM staff in retirement decisions would be too complex. “They won’t necessarily be involved in study scope discussions,” he said.
In comments to MISO, NIPSCO said it was generally supportive of the proposed changes, but it asked the RTOs to devise a timeline for retirement studies that is similar to MISO’s multistep interconnection queue studies. MISO responded that an interconnection format isn’t feasible because its generator retirement studies are “conducted on an ad hoc basis,” and studies can vary.
NIPSCO also asked MISO for examples of how identified transmission projects become approved under the new process. MISO said the issue would be discussed at a future IPSAC meeting.
Reddoch asked for stakeholder input by Nov. 1 and said MISO would share final JOA language at the Nov. 15 Joint and Common Market meeting with PJM.
FERC last week approved a settlement allowing independent transmission developer TransCanyon to collect a 9.8% base return on equity for any projects it builds under CAISO’s FERC Order 1000 competitive solicitation process (ER15-1682).
TransCanyon asked the commission last May for a 10.6% ROE if it were selected to build and operate a 115-mile, 500-kV transmission segment linking Southern California Edison’s Colorado River substation with Arizona Public Service’s Delaney substation. The commission set the request for hearing and settlement procedures in July 2015.
CAISO ultimately awarded the economically driven $300 million Delaney-Colorado River project to a joint venture between Abengoa and Starwood Energy.
Delaney – Colorado River Project Map | CAISO
Still, last week’s order will enable TransCanyon to incorporate the 9.8% ROE into its transmission owner tariff’s formula rate template — the basis for calculating a yearly transmission revenue requirement to be included in the ISO’s transmission access charge.
Participants in the settlement were SoCalEd; the cities of Anaheim, Azusa, Banning, Colton, Pasadena, Riverside and Santa Clara; the California Department of Water Resources; the M-S-R Public Power Agency; and Modesto Irrigation District.
TransCanyon is a joint venture between Berkshire Hathaway Energy, which owns PacifiCorp and NV Energy, and Pinnacle West Capital’s Bright Canyon Energy. Arizona Public Service is Pinnacle’s primary subsidiary.
COLUMBUS, Ohio — Three economists, two lawyers and an electrical engineer walk into a bar…
Actually, they appeared on stage here for the latest installment in PJM’s ongoing debate over the role and value of financial transactions.
Independent Market Monitor Joe Bowring and the Massachusetts Institute of Technology’s John Parsons, both economists, explained to the annual meeting of the Organization of PJM States Inc. why they are critical of PJM’s current system for auction revenue rights and financial transmission rights.
Parsons cited the Monitor’s finding that PJM load has lost out on $1.7 billion in unreturned congestion surpluses over the past five years. That total, an average of almost $335 million a year, represents the difference between what load paid for ARRs and FTRs and what was returned to it. (See Table 13-37 in the Monitor’s second-quarter State of the Market report.)
Harvard economist William Hogan, whose theories have provided the basis for the structure, said he’s not sure of Bowring’s math, but he said it fails to capture all the dynamics of the system.
Hogan said ARRs and FTRs were not designed to return congestion revenue to load as Parsons and Bowring contend, but to solve the “dynamic efficiency” problem — a way to hedge congestion costs in recognition that physical transmission rights are impossible under an open access transmission system. “If you want to have open access and nondiscrimination [in an electricity transmission system], this is the only way to do it,” he said.
PJM’s system is designed so demand customers pay their LMPs and power generators are paid their own LMPs. Load overpays by design, and the surplus in those congestion payments is supposed to be returned to load customers through FTRs and their associated ARRs, Parsons and Bowring contend. ARRs are created when the rights to FTR payments are auctioned off to hedge against the variability of FTRs. It’s through these markets that the differences between customers’ congestion payments and the FTR/ARR offsets they receive are created.
While some FTR buyers no doubt are speculators hoping to pay less than they’ll receive in congestion payments, Hogan said they are still providing fixed-price hedges to sellers looking for predictability. “The beneficiaries of the ultimate transmission congestion are the people on the load side, not the FTR holders.”
Parsons countered that the system is not “confronting honestly” how random and imprecise — or “stochastic,” as he put it — capacity can be on a transmission system. “The system is designed to kill two birds with one stone, but … have you ever seen anybody who can actually kill two birds with one stone?”
‘Fairy Tale’
“What you have right now is a fairy tale FTR system where rights are designed upfront, but you don’t know the right capacity of the system,” he continued. “You don’t have a product that actually reflects the true congestion and the true capacity under a point-to-point system. It would be better to step back and structure the system so that actually reflects the true congestion revenues and risks and the true capacity and risk.”
Bowring repeated his longstanding position that the benefits of financial trading to the market have not been proven — a statement that brought a scowl to the face of attorney Noha Sidhom of Inertia Power, a financial firm that trades FTRs.
The nodal concept using LMPs came about to address the inability to control the flow of electricity across the network, Bowring said. However, that’s the point when explicit point-to-point contract paths — the concept on which FTRs are based — became obsolete, he argued.
Stu Bresler, PJM senior vice president for operations and markets, acknowledged that FTRs were a design choice made in 1999, long before its full implications could be known.
“Joe’s correct that it was a simpler time back then,” said Bresler, the electrical engineer in the group. “The implementation of the monthly FTR auction was intended to give market participants the ability to have additional choices with what to do with their allocated rights.”
The economists’ theoretical debate was juxtaposed with real-world experience from Sidhom and attorney Marji Philips of Direct Energy, a load-serving entity that receives and sells FTRs.
Philips said economists’ idyllic theories don’t account for the vagaries of PJM’s system. Despite all the modeling, market designs don’t account for everything, she said, and what’s left will undoubtedly follow the industry maxim that “load pays.” She cited FERC’s Sept. 15 order directing PJM to allocate balancing congestion to real-time load (EL16-6-001, ER16-121).
“There are causes of congestion that we don’t actually have pure cost causation [for], and the new FERC order says, ‘Well, let’s just stick it to real-time load because we don’t know where they’re coming from, and we think this should be a pure product.’ They have undermined the complete value of FTRs for load, which is to hedge our congestion risk,” she said. “What I love is that FERC says, ‘This is for load.’ Not a single load entity supported it.” (See Monitor Says FERC Erred in PJM FTR Ruling, Seeks Rehearing.)
Sidhom agreed that the market needs some tweaks, such as enhanced modeling, but insisted it provides an important service. She cited a MISO study that concluded optimizing wind into the RTO is saving consumers $316 million to $377 million annually — savings due in part, she said, to the work of financial traders. “Not bad for a 76 cents/MWh cost hedge,” she said. “I think that’s a great deal for consumers.”
“At the end of the day,” she added, “you need those FTR auctions to provide the appropriate pricing.”
WESTBOROUGH, Mass. — ISO-NE’s latest briefing on its ongoing economic study focused on the shortfall of energy market revenues, prospects for storage and the ability to meet increased renewable portfolio standards.
Planners told the Planning Advisory Committee on Wednesday that uplift and capacity revenues will become increasingly important because energy market revenues will be insufficient to support any form of new generation in 2025 or 2030, the two time horizons in the draft study.
“Additional revenue from other sources will be needed to support new resources, as the energy market contribution isn’t sufficient to cover fixed costs,” said Michael Henderson, director of regional planning and coordination at ISO-NE.
In the simulations, energy market revenues are below annual carrying charges for all new generation resources, including wind, solar photovoltaic, natural gas combined cycle and combustion turbines. Units would recover some costs through energy market revenues plus uplift, the study says. Resources also would need “significant revenues” from the capacity market, Henderson added.
The study says the shortfall results because cheap gas-fired units typically set LMPs and higher-cost resources are rarely on the margin.
Another factor is low- or no-cost resources. The region is experiencing little or no load growth as the states have made significant commitments to behind-the-meter solar resources and energy efficiency. Wind and PV that aren’t behind the meter are price takers.
Uplift would be highest in 2025 under scenario 2 — in which all additional capacity needs, including retirements, are met with new renewable and clean energy resources, including nuclear power — hitting almost $179 million assuming no transmission constraints.
The lowest uplift — $88 million — is under scenario 5, in which RPS requirements are met by resources interconnected to the system, under construction or approved as of April 1, 2016, with alternative compliance payments used to meet any remaining RPS requirements. Retired units would be replaced with combined cycle plants to meet installed capacity requirements.
In 2015, uplift payments to resources operated out of merit — typically to ensure power system reliability — totaled $119 million, 2% of the total energy payments of $5.9 billion, according to Internal Market Monitor’s 2015 Annual Markets Report.
Energy Storage
The study found that net revenues for energy storage increase along with more production by renewable resources.
Net revenues would be highest under the “RPS-plus scenario,” which assumes additional renewable and clean energy resources above existing RPS requirements. Annual net revenues — revenue from generation minus the cost of storing energy — are projected to total more than $12 million in 2025 under the scenario, assuming no transmission constraints.
By contrast, storage would show negative net revenues of $1.5 million under scenario 5.
Increasing RPS
The study finds that scenarios 1, 2 and 3 all can meet the projected growth in the new RPS target for 2025 (8,069 GWh) and 2030 (10,806 GWh), although scenario 1 barely meets the 2030 target under a constrained transmission system.
Meeting the RPS targets under scenarios 4 and 5 would require the addition of more renewable resources, imports, alternative compliance payments or reducing RPS targets by adding energy efficiency and behind-the-meter solar.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:20)
Members will be asked to endorse the following manual changes:
A. Manual 14A: Generation and Transmission Interconnection Process. Revisions, recommended by the Earlier Queue Submittal Task Force, include: changes to the assignment of queue priority; timing, including scheduling of deficiency reviews; criteria for inclusion in feasibility studies; and fee structures.
3. Installed Reserve Margin Study Results (9:20-9:30)
Members will be asked to endorse the 2016 Installed Reserve Margin study results. (See “More Granularity Requested on Winter Reserve Targets,” PJM Planning Committee Briefs.)
4. Credit Subcommittee (9:30-9:40)
Members will be asked to endorse proposed clarifications to the credit policy in Tariff Attachment Q that reorganize provisions and make five minor changes to them, none of which affects credit requirements. (See “Attachment Q Modified; Credit Requirements Unaffected,” PJM Market Implementation Committee Briefs.)
5. PJM Capacity Problem Statement / Issue Charge (9:40-10:25)
6. Market Implementation Committee Charter (10:25-10:30)
Members will be asked to approve the updated Market Implementation Committee charter, which removes references to working groups. (See “‘Working Groups’ Removed from MIC Charter,” PJM Market Implementation Committee Briefs.)
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to endorse:
B. Tariff revisions regarding the release of capacity in the third incremental auction for the 2017/18 delivery year in response to a FERC reporting directive (ER16-532) related to excess capacity procured in the Capacity Performance transition incremental auction. (See “Proposal Chosen for Capacity Release,” PJM Markets and Reliability and Members Committees Briefs.)
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.
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.