VALLEY FORGE, Pa. — The PJM Market Implementation Committee will hold a special meeting June 29 to continue discussion about the process for approving fuel cost policies and redefining terms, including “market seller.”
The changes, which stem from an annual review of Manual 15, were on the MIC’s agenda for endorsement Wednesday, but after spending one and a half hours talking about them, members asked to continue to work the issue.
One of the topics of discussion was new language added to clarify that the “market seller is the entity that submits a cost-based offer and is responsible for maintaining all information necessary to calculate resource’s cost-based offer.”
Members said they wanted to make sure that any new definitions were consistent with the Tariff.
Catherine Mooney of Monitoring Analytics also proposed language changes on behalf of the Independent Market Monitor.
“The purpose of Manual 15 is to develop the primary input for market power mitigation. This is one of the Market Monitor’s primary responsibilities,” she said.
In a case where a market seller is an agent of the generation owner, it needs to have access to all of the information required to not only calculate but also support a cost-based offer, she said.
Mooney also introduced language that would clarify the Monitor’s authority in evaluating fuel cost policies.
More Flexible Parameter Limited Exception Process Approved
The committee, with two abstentions, endorsed a proposal to make the parameter limited schedule exception process more flexible.
“The most important goal is to solve the problem of inflexibility,” PJM’s Tong Zhao said. (See “Manual Changes to Detail Unit-Specific Operating Parameter Adjustment Process under CP,” PJM Operating Committee Briefs.)
The revisions allow generators to request an exception if they learn of a need after the Feb. 28 deadline. They also permit a temporary exception to be extended to a period or a persistent exception if the need arises after the deadline.
In addition, the changes give PJM and the Monitor more time to review requests and give their determinations to market sellers.
Retroactive Black Start Billing Charges Focus of Proposed Study
PJM’s Tom Hauske introduced a problem statement and issue charge designed to mitigate the potential for large, retroactive black start charges.
Currently, the Tariff does not address when the Monitor will review the costs for new units entering black start service outside of the annual revenue recalculation period.
A number of new units have recently entered black start service, many replacing retiring units. To ensure PJM had sufficient resources, most of these new units entered service before their initial capital costs and annual revenue requirements were approved by the Monitor — some with a lag of six months or longer.
That resulted in significant charges to load in April.
“We would all benefit from more transparency. … If you have these things under review for a period of time and they’re accumulating charges, we’d like to see how large that accumulation might be,” said Jeff Whitehead of Direct Energy. “If we could minimize it, that would be good. If we can’t, we need to at least understand what the liability is going to be.”
“The back charges were a shock to our members and clients,” added Carl Johnson of the PJM Public Power Coalition. “Even if we don’t know what the scope of that is going to be, just knowing it exists is helpful.”
“There are more coming,” Hauske replied. “We can come up with an estimate.”
Conference Call Set to Discuss Auction-Specific Bilateral Transactions
A special MIC conference call will be held June 24 to discuss proposed clarifications to auction-specific bilateral transactions.
Assistant General Counsel Jen Tribulski said the changes aim to preserve the physicality of the transactions and ensure members’ indemnification.
The new rules assign auction credits and bonus payments to the buyer, while the seller retains the obligation to perform. (See “PJM Proposes Clarifications to Bilateral Transactions,” PJM Market Implementation Committee Briefs.)
Members said they wanted more information on the clarifications.
Committee Endorses Two Problem Statements from Members
With little discussion, the committee unanimously approved:
A problem statement and issue charge presented by Bruce Campbell of CPower to review the demand response registration submission deadline. (See “CPower Proposes to Study Necessity of DR Registration Submission Deadline,” PJM Market Implementation Briefs.)
A problem statement and issue charge from Direct Energy’s Whitehead and Sharon Midgley of Exelon to discuss potential enhancements to the residual auction revenue rights process. (See “Exelon, Direct Energy Suggest Studying Residual ARR Process,” PJM Market Implementation Committee Briefs.)
SPP and MISO have ended months of uncertainty by agreeing to a second joint system study, which will take a “targeted” look at the two entities’ newly created Integrated System seam in the Upper Midwest.
SPP staff told the Seams Steering Committee, which met in Dallas on June 8, that the MISO members of the Interregional Planning Stakeholder Advisory Committee (IPSAC) voted last month to pursue the study. The Joint Planning Committee, composed of SPP’s David Kelley, director of interregional relations, and MISO’s Eric Thoms, manager of planning coordination and strategy, made it official May 31 when the two agreed to begin the study.
The RTOs conducted their first joint study last year, identifying three potential interregional transmission projects. However, they were unable to reach agreement on pursuing any of them. (See SPP, MISO Conclude Joint Study Empty-Handed.)
SPP’s interregional coordinator, Adam Bell, said both staffs have begun discussions on the study’s scope. He said the staffs are planning to discuss the draft scope at a possible IPSAC meeting in July and hopes to wrap up the study in the first quarter of 2017.
Kelley told the committee both staffs have a “desire” to do a larger study, but they are constrained by lack of manpower.
Bell said SPP will continue discussions with MISO to incorporate process improvements identified by stakeholders during the IPSAC’s March meeting.
Staff told the committee the study is focused on five “target areas” in AECI’s footprint where there have been recurring operational problems:
Northeast Oklahoma (potential overloads, voltage issues);
Southwest Missouri (potential overloads, voltage issues);
Central Missouri (potential low-voltage issues);
Wheaton area, southwest Missouri (potential upgrades); and
Mid-Missouri (potential low voltages).
“The scope was intentionally left broad to give us the flexibility we need to create these … areas and most efficiently target them,” Bell said. “Some stem from operational issues we see regularly that aren’t showing up in typical planning areas.”
The models are to be developed by the end of July, with preliminary results due in November and a final report in January.
Committee Recommends SPP Intervene in FERC’s NIPSCO Docket
The SSC unanimously endorsed a motion recommending SPP intervene at FERC in an ongoing dispute between MISO and PJM over their interregional planning (EL 13-88).
MISO and PJM have until June 20 to submit a compliance filing responding to an April 21 order in which the commission partially denied and granted a 2013 complaint by Northern Indiana Public Service Co. over the RTOs’ processes. (See MISO, PJM Working to Comply with NIPSCO Order.)
SPP’s options are limited because it did not intervene before the order was issued. Given choices between intervening out-of-time, commenting on MISO’s eventual compliance order or petitioning for a declaratory order, the committee voted to recommend the RTO “intervene out-of-time without comments but justification.”
“It’s really hard to come in at this late stage and ask for standing in the case,” Kelley said. He suggested SPP could intervene once MISO and PJM make their filing and potential Tariff changes.
The vote was partially driven by SPP member ITC Holdings’ intervention in the case. ITC, one of seven intervenors to request a rehearing of the order, said the commission should clarify that its directives to MISO also apply to potential interregional economic projects along the SPP-MISO seam.
FERC directed MISO to lower its interregional project voltage threshold with PJM from 345 kV to 100 kV and remove the $5 million minimum cost requirement. MISO currently has the same 345-kV threshold for economic projects along its seam with SPP, which has limited the ability of the entities to agree on interregional projects.
Staff reminded members that FERC is under no obligation to accept ITC’s request or clarify the applicability issue.
“My analysis leads me to believe … the commissioners probably won’t answer ITC,” SPP attorney Matthew Harward said. “If it grants ITC’s request for clarification, that could potentially impact SPP.”
Harward said he understood that several motions opposing ITC’s request have been filed, but he had yet to review them.
Kelley said MISO staff has told him the RTO is “taking the policy position that these things do not apply” to SPP and MISO and that the order is related only to the MISO-PJM seam.
Harward seemed to agree. “The order is narrowly drawn for the PJM-MISO seam,” he said.
Apple’s newly formed energy subsidiary has filed with FERC to begin selling wholesale power from its solar facilities in California and Nevada (ER16-1887).
Apple Energy, formed on May 20 and headquartered in Delaware, asked FERC last week for market-based rate authority to offer capacity and other services, such as spinning reserves, frequency response and operating reserves, in CAISO.
However, the company also seeks permission to sell in NYISO, MISO, ISO-NE, SPP and PJM, suggesting further expansion. The company asked for approval within 60 days of the filing.
WPPI Energy, a Wisconsin public power supplier, said it is looking to secure 100 MW of renewable energy for its companies in Wisconsin, Michigan and Iowa to meet regulatory mandates in those states.
WPPI, which serves 51 municipal electric utilities in the three states, already has several wind projects in development. Its current plan is to sign power purchase agreements stretching 20 years or more, the company said.
French defense contractor DCNS Group has formed a partnership with Maine Aqua Ventus, the University of Maine-led consortium developing a floating offshore wind farm.
Maine Aqua Ventus aims to build a 12-MW wind farm near Monhegan Island in a pilot program supported by the U.S. Department of Energy. The role of DCNS, which builds submarines and naval vessels, is still being defined, according to the consortium.
Frederic Le Lidec, DCNS’s marine renewable energy director, said the company is working on three marine renewable technologies: tidal energy, ocean thermal energy conversion and offshore wind. He said DCNS is offering its services in engineering, construction, installation, maintenance and project management.
Shell Chemical Appalachia announced plans to build a massive, multibillion-dollar ethane cracker plant near Pittsburgh.
The plant will need 105,000 barrels of ethane a day, produced in the Marcellus and Utica shale fields of Pennsylvania, Ohio and West Virginia. It will break down, or “crack,” that ethane into 1.5 million metric tons of ethylene, a chemical used in the production of plastic, a year.
The complex will receive $1.65 billion in tax credits spread over a quarter century. Pennsylvania officials hope the complex will spur other industries in the area. Shell will begin construction within 18 months on the grounds of a former zinc smelter in Beaver County. While the company wouldn’t give an exact cost of the project, a similar ethane cracker in Lake Charles, La., cost $11 billion.
Exelon to File for 20-year Extension for Peach Bottom
Only days after announcing that it will close two nuclear generating stations in Illinois, and that another in Pennsylvania is at risk, Exelon Generation announced that it will seek a 20-year extension for its Peach Bottom Atomic Power Station in Delta, Pa.
The licenses for the plant’s two reactors expire in 2033 and 2034, but the company said it will file for the extensions in 2018. Reactor license renewals typically take about two years to make their way through the Nuclear Regulatory Commission process.
The Dairyland Power Cooperative has agreed to buy the output of a proposed 98-MW wind farm near Platteville, Wis., nearly tripling the co-op’s wind capacity.
The 49-turbine Quilt Block wind farm is gathering regulatory approval and is scheduled to come online by the end of 2017.
Dairyland’s agreement would increase wind’s contribution to its load from 4.5% to 12.6%. The co-op has a goal to source 18% of its power from wind by 2025.
DTE Energy will close eight coal-fired units at three Michigan plants in the next seven years.
The Detroit utility said the affected units at its River Rouge, St. Clair and Trenton plants will be retired between 2020 and 2023. The three plants represent a quarter of the company’s total electricity production. The utility said employees impacted by the shutdowns will be offered jobs at its other facilities.
The move will leave DTE with just six coal-fired units of the 17 it had in 2015. Earlier this year, DTE retired three other coal-fired units and said the lost generation would be replaced with wind, solar and natural gas resources.
Dominion’s Chesapeake Center Coal Ash Estimate Triples
Dominion Virginia Power has three times as much coal ash stored at the company’s Chesapeake Energy Center near Norfolk than it previously estimated, according to documents received as part of a Sierra Club suit.
Dominion previously estimated the amount of coal ash at the site was about 1 million tons. But the company’s newer estimates say the three impoundments contain about 3 million tons.
The Sierra Club is asking in a civil suit for the company to remove all of the ash from the site to a lined landfill away from the Elizabeth River to prevent heavy metals from leaching into groundwater and into the river. The suit is scheduled to be heard later this month.
Toyota’s massive new North American headquarters in Plano, Texas, will draw about 25% of its electricity from a 7.73-MW solar facility mounted on three parking garages.
In the project’s first phase, two 2.45-MW systems will be installed by August 2017, with a 2.83-MW system by December 2017. The seven-building campus, which is about halfway finished, is expected to be completed sometime in 2017.
Toyota did not disclose the cost of the facility, one of the largest in the state. The company estimates the entire campus and moving costs for employees will total about $1 billion.
Talen Energy is in the process of selecting an entity to construct, own and operate a 15-mile pipeline to bring natural gas to the 1,500-MW Montour plant as part of a project to convert its two coal-fired units to dual-fuel by 2018.
The estimated cost of modifying the plant in north-central Pennsylvania, near the Marcellus Shale natural gas fields, is about $70 million.
“The Montour plant is located in close proximity to one of the largest natural gas formations in the world, the Marcellus shale,” Talen CEO Paul Farr said. “Co-firing the plant to burn natural gas produced in Pennsylvania enables Talen Energy to leverage the strategic location of the plant.”
Solar industry veteran Shihab Kuran has founded a company to offer modular grid-scale lithium-ion battery systems that can be delivered by truck, train or barge.
The Power Edison systems travel in special containers that can be stacked like Legos and shipped according to shifting demand.
“We are the Uber of battery storage,” said Kuran, who also founded solar energy generation company Petra Systems. “We’re going to offer a solution for the duration that it’s needed, and, after that, we’ll take our solution and repurpose that for other applications.”
Cooperative Hires Lightower To Build Fiber Network
The Delaware Electric Cooperative has chosen Lightower Fiber Networks to build a 250-mile, custom fiber network that will provide a secure way for the co-op to communicate with substations and remote advanced electrical equipment.
The project, which connects 28 sites in Delaware, includes the construction of 180 miles of new network.
Cities to Break Contracts with Indiana Michigan Power
Nearly a dozen cities in Indiana and Michigan have given Indiana Michigan Power the required four-year notice to end their power purchase agreements. The cities, which all belong to the Indiana Michigan Municipal Distributors Association, plan to break their contracts in 2020, six years earlier than the agreements were originally slated to end.
A city administrator in Niles, Mich., estimated that the city is paying 30% more than market price for electricity, while a general manager for Mishawaka Utilities, in Indiana, put the figure at around 20% over market value.
While the cities could individually buy electricity from other utilities, they can also renegotiate a deal with Indiana Michigan Power.
AUSTIN, Texas — The Public Utility Commission of Texas approved a plan for a hybrid above/below-ground transmission line in the City of Frisco (Docket No. 44060). The project was notable for the financial commitment the city offered to bury the majority of the line. (See Texas PUC OKs Undergrounding Tx Line; City Agrees to Foot Cost.)
While the all-underground route would have cost more than $34 million — nearly $29 million more than the all-overhead route the PUC preliminarily approved — the city has agreed to pay approximately $13 million of the extra cost to have the lines buried in conjunction with an upcoming road-widening and waterline-installation project.
The cost savings of coordinating the projects was factored into the city’s calculations, along with other implications, such as where the project will be sited. The city contended that Brazos Electric Cooperative, the utility overseeing the project, would have had to pay for the right of way, but said it would donate it if the line was sited underground. This, along with some design modifications, brought the cost difference to approximately $4.3 million.
Briefs for ‘Precedential’ Decision
Commissioners called for parties involved in a substation-siting dispute to provide briefs on whether the PUC has jurisdiction in the case (Docket No. 45175). The Colony, a city near Dallas, is arguing that it has jurisdiction under the state’s Public Utility Regulatory Act to determine where the station can go. The local electric co-ops — Brazos and Denton County Electric — believe the PUC has authority under a different section of the same law.
Chairman Donna L. Nelson said the call for briefs in what she called a potentially “precedential” case was very wide to “get to the real heart of the conflict.”
Commissioner Kenneth W. Anderson Jr. said the commissioners gain much more insight from back-and-forth replies to other briefs, where the parties tend to “savage” each other.
‘More Meat’ Needed for New Interconnection Rule
The commission also adopted a rule to comply with several statutes that affect the paperwork necessary to tie into ERCOT’s grid (Project No. 45124). However, Anderson requested that, following the final approval, PUC staff open a new rulemaking process “to clarify the gaps that the statute doesn’t cover.” He said commission rules should delineate, among other things from the statute, what ERCOT should study to meet its need and reliability criteria, the impact on ERCOT’s market and the process to receive approval for a DC tie into the system.
All of these could have unforeseen consequences. For example, commenters pointed out that ERCOT’s handling of DC ties could — if too broadly defined — affect ERCOT’s independence from FERC jurisdiction.
“We need to put a little more meat on the bones of this rule because it’s not like the normal transmission asset,” he said.
‘Deceptive’ Offers on Customer-Choice Website
Saying that she continues to be “bothered” by “deceptive” offers on the website customers use to choose a power generator, Nelson announced a stakeholder meeting in her office June 21 to address the issue (Project No. 45730).
“Sometimes, I think things move a little faster when a commissioner gets involved,” she said. “The Power to Choose website kind of needs some work right now. The whole concept of choice doesn’t work if customers aren’t educated about what they’re buying.”
Anderson said he’s still “convinced” of the necessity of the website and that the only questions are exactly what might change. He said he uses it to shop and has always paid less than the last regulated rate.
The commissioners cautioned retail energy providers against putting out offers that are significantly below cost or whose rate requires meeting unreasonably specific consumption targets. However, they also disapproved of requiring retail electric providers to create standardized offers, saying those would be anti-competitive.
Though the site isn’t perfect, Commissioner Brandy Marty Marquez urged consumers who are overwhelmed by the shopping process to request a tutorial from PUC staff, who find it “one of the most exciting things” to do, she said.
‘Shock’ over SPP Z2 Billing Plans
Marquez said it was “shocking” that SPP plans to request repayment over 10 months of transmission upgrades that were approved over a period of more than eight years. (See related story, Z2 Project Faces Further Hurdles, Possible Delay.)
The commissioners said they were concerned for ratepayers shouldering the burden of the repayments over such a short period.
Additional Actions
The commission also:
Approved applications by American Electric Power’s Texas affiliates, Texas New Mexico Power, Oncor, CenterPoint Energy and Sharyland Utilities to adjust their energy-efficiency cost-recovery factors.
Returned to an administrative law judge the application by Luminant and Oncor to transfer ownership and administration of the decommissioning trust for Comanche Peak Nuclear Power Plant. The application was based on a plan that is being changed and resubmitted by the bankruptcy court overseeing the decommissioning process, so it needed to be revised.
Approved publishing a proposed rule on how distributed generation facilities can connect to the grid (Project No. 45078). The proposal would allow interconnection agreements to include the end-use customer, the owner of the DG facility, an owner of rights to energy produced from the DG facility or the owner of the premises at which the DG facility is located.
The Supreme Court on Monday declined to review a D.C. Circuit Court of Appeals ruling allowing EPA to continue enforcing its Mercury and Air Toxics Standards (MATS) while the agency complies with a 2015 high court ruling to address procedural issues (15-1152, Michigan, et al. V. EPA, et al.).
In the 2015 decision, the court found that EPA had failed to take costs into consideration when deciding whether the MATS rule was “appropriate and necessary” under the Clean Air Act. The court allowed EPA to continue enforcing the rule, however, while the agency addressed the court’s concerns. The agency responded with a supplemental finding, saying the cost review did not change its opinion on the need for the rule and proposing to leave MATS unchanged.
Several states asked the D.C. Circuit to require the agency to conduct a new rulemaking, a request the court rejected in December. The litigation is largely moot: Most power plants covered by the rule complied or retired by the deadline of April 2015. Some plants received a one-year extension on the deadline, which has also passed.
A report by the International Energy Agency says that subsidies are still needed to ensure continued growth of renewable energy.
Government subsidies make renewable energy projects less risky investments. But the IEA warns that as the energy generated by renewables becomes less expensive, governments may look to scale back the subsidies.
“As we enter this new phase, the question becomes what can the policymaker do to maintain bankability [and] reduce the risk of investments in generation without just throwing subsidies out, which isn’t where anyone wants to be,” said Toby Couture, director at the German renewable energy consultancy E3 Analytics and an author of IEA’s report.
Scientists working in Iceland are testing a new method of carbon capture and sequestration, injecting CO2 from a geothermal plant into basalt to form calcite, theoretically locking the gas in the ground permanently.
CarbFix, as the project is known, has so far resulted in about 95% of the CO2 injected being converted to calcite. So much calcite was formed by the testing process that a pump used to test the water became clogged with the mineral. The scientists found that the calcite formed in less than two years.
Iceland is practically all basalt, making it an ideal location to test the new method. The project is being conducted in partnership with the Icelandic capital’s municipal utility, Reykjavik Energy, at a plant about 15 miles east of the city. Work is being done now to figure out a way to scale the project up to industrial sizes and to find other suitable locations with enough basalt.
Report: US Solar Installations To Double in Coming Year
Developers rushing to meet a deadline for a federal solar tax credit are driving U.S. solar installations to nearly double the total capacity in 2016, according to a report by GTM Research. By the end of the year, 14.5 GW of solar capacity will be online, the report says.
Solar installations rose 24% in the first quarter this year, about 64% of all new electric generation capacity during that period, according to the report.
Most of the utility-scale projects were pushed through on expectation of the year-end solar tax credit expiration. The credit was extended for five more years, however. The extension will spur more than 20 GW of additional solar capacity by 2021, GTM said, though the utility-scale market is expected to contract next year and in 2018.
FERC has granted the request for new hearings on Transco’s Garden State Expansion project after a group of municipalities said the company failed to give proper notice of meetings and didn’t meet environmental requirements.
Although not a large project — it involves a new compressor station, upgrades to another substation and upgrading some existing pipeline — the municipalities and environmentalists called it a win.
“Anytime we get FERC to reopen a docket and have a rehearing is an environmental victory,” said Jeff Tittel, New Jersey Sierra Club director. “FERC almost never grants a rehearing and the fact that they did it shows that there were significant problems in the approval of Transco’s application.”
The Nuclear Regulatory Commission held its annual public meeting on the operation of Entergy’s Indian Point nuclear station, and things got heated, with members of the public telling the commission it is failing in its job to keep the plant operating safely.
“You don’t care about our lives, you don’t care about our future,” said Susan Shapiro, who identified herself as a member of the Indian Point Safe Energy Coalition, a protest group. “All you care about is how you are going to grease the pockets of Entergy.”
David Lew, an NRC deputy administrator overseeing the northeast region, said Indian Point is operating within guidelines. “Our overall conclusion is that Indian Point operates safely and will continue to operate safely,” he said.
Talen Energy, operator of the Susquehanna nuclear plant in Pennsylvania, reported the discovery of two small leaks of radioactive water while shutting Unit 1 down last week for regular maintenance.
Staff discovered one leak inside the containment structure and a second leak in lines leading to instrumentation sections of the unit. Both leaks were contained and there was no danger, according to the report made to the Nuclear Regulatory Commission.
“When the plant is operating, there are certain areas you can’t access when it’s in power,” said spokesman Todd L. Martin. “When we did the downpower to address the initial leak, that’s when we found this additional leakage, and that prompted the second notification.”
FERC last week revoked authorization for Berkshire Hathaway Energy subsidiaries to sell wholesale power at market-based rates in four neighboring balancing authority areas in the West.
The commission ruled that Berkshire failed to prove that its affiliates — which include PacifiCorp, NV Energy and 19 other generating entities — do not exercise horizontal market power in the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern Energy areas (ER10-2475, et al.).
“In the absence of reliable delivered price test (DPT) analyses rebutting the presumption of market power, we find that the continuation of the Berkshire [subsidiaries’] market-based rate authority in these four balancing authority areas is not just and reasonable,” the commission said.
Berkshire Hathaway Energy’s subsidiaries will be restricted from selling at market-based rates in the PACE, PACW, NWMT, and IPCO areas represented on the map.
FERC ordered the companies to file revised tariffs limiting their market-based sales to regions outside the four areas within 30 days. The companies must also issue refunds for the period between January 9, 2015, and April 9, 2016.
The decision left intact Berkshire market-based rate authority in the Arizona Public Service, Bonneville Power Administration, Los Angeles Department of Water and Power, Western Area Power Administration Colorado-Missouri and WAPA Lower Colorado balancing authority areas, as well as in CAISO.
Berkshire companies are already prohibited from selling power at market-based rates in the NV Energy area covering most of Nevada.
FERC’s ruling marks the second such setback for Berkshire in less than a month. In May, the commission declined to rehear a 2015 decision that prohibits PacifiCorp and NV Energy from offering energy into the Western Energy Imbalance Market (EIM) at prices above default energy bids because of concerns about the companies’ combined market power. (See Berkshire Denied Rehearing on EIM Market Power.)
The June 9 order stems from Berkshire’s 2013 acquisition of NV Energy, which put Warren Buffett’s energy conglomerate in control of more than 19 GW of generation serving states throughout the western U.S. In light of the acquisition, the commission instituted a Section 206 proceeding requiring the Berkshire companies to submit evidence that their market-based rate authority remained valid in the four areas in question.
While the Berkshire companies failed the indicative “pivotal supplier” and “wholesale market power” screens for initially assessing horizontal market power in the four areas, FERC policy allows a power supplier to rebut that presumption by performing a more thorough DPT analysis. The DPT factors in native load commitments to determine a supplier’s “available economic capacity” — energy available for offer in the open market — over 10 different seasons and load conditions. The analysis must also consider the load commitments for and available supply from other generators in the region.
FERC’s decision to revoke Berkshire’s market-based rate authority ultimately rested on what the commission called a “flawed” DPT analysis from the company. The commission focused in particular on Berkshire’s failure to calculate unique season and load levels for each of the four areas, instead relying on assumptions based on data for only the PACE area.
One example cited by the commission: “In the Idaho Power balancing authority area, Idaho Power would likely not be a competing supplier in certain season/load levels in the [available economic capacity] analysis, even though it is listed as having the most competing capacity in many of the season/load levels.
“The Berkshire [companies] are attempting to demonstrate that they do not have market power in four different balancing authority areas,” the commission continued. “In order to do so, the DPT analyses submitted by the Berkshire [companies] should have used inputs, assumptions and facts appropriate to the unique characteristics of each balancing authority area when studying that particular area.”
As a result of the decision, the Berkshire companies must each submit tariff revisions providing for default cost-based rates for the PACE, PACW, Idaho Power and NorthWestern areas — or inform the commission of their intention to use any cost-based tariff currently on file.
PacifiCorp — the largest Berkshire entity affected by the ruling — told RTO Insider that it continues to review the order but expects “limited impact” because of the small number of transactions involved.
“The bulk of PacifiCorp’s wholesale sales occur at trading hubs that are outside the areas affected by the order, or within the Energy Imbalance Market, which is also not impacted by the order,” spokesman Bob Gravely said.
Asked whether the ruling would strengthen the case for PacifiCorp to join CAISO in an effort to reduce market power concerns, Gravely said, “This ruling shouldn’t impact one way or the other the decision to join a regional ISO. Issues such as governance and ensuring overall net benefits for customers are what will ultimately drive that decision.”
“There will be a point where we stop asking questions,” FERC’s Arnie Quinn promised during a panel discussion at the Energy Bar Association’s Annual Meeting last week.
That point will come after the commission reviews the transcript of last month’s technical conference on the subject and the post-conference comments it is now soliciting.
The commission’s questions started in 2008, when it asked the RTOs to make proposals to reduce interconnection backlogs (AD08-2). The grid operators offered a number of changes, including clustering interconnection studies by location and establishing development milestones to weed out projects not progressing toward commercial development.
But the changes haven’t ended developers’ complaints about study delays or the difficulty in predicting interconnection costs. At the technical conference, transmission operators countered that the delays are caused by the high number of speculative interconnection requests, which force them to conduct restudies when a project drops out of the queue. (See Generators, Tx Operators Spar over Interconnection Processes Before FERC.)
After that, the commission could respond with a prescriptive rulemaking, a policy statement — which wouldn’t require transmission operators to make any changes — or a hybrid of the two, said Quinn, director of FERC’s Office of Energy Policy and Innovation.
“The difficulty with this topic … is it’s fairly straightforward to define the problem,” Quinn said. “Identifying the solutions that are going to work everyplace — that’s the harder nut to crack.”
Incremental, Comprehensive Changes Sought
Last month’s conference was called in response to a rulemaking request by the American Wind Energy Association, which argued that existing interconnection rules are outdated and discriminatory.
Panel moderator John Moore, of the Natural Resources Defense Council, opened the EBA session last week by quoting from Invenergy’s testimony at the conference, in which the company related its experiences on the length of the interconnection processes: SPP (one year); PJM (two years); CAISO (two and a half years); MISO (“has seldom taken less than three years”); and NYISO (as long as six to seven years). “An interconnection process lasting three years or more can kill even the most serious of projects,” Invenergy’s Kris Zadlo said.
Quinn said he concluded from the conference testimony that developers are seeking both incremental improvements — including more access to models and the ability to self-construct interconnection facilities — and more comprehensive changes.
The comprehensive proposals are more controversial, Quinn said, citing a call for closer coordination between the transmission planning and the interconnection processes. “Instead of serially studying a bunch of projects over time, just identify an area on the transmission system where you’ll need some upgrades. Using the transmission planning process to do that might smooth the interconnection process,” Quinn explained.
The controversy? “Transmission is usually paid for by load; interconnection upgrades are typically paid for by the interconnection customers. So that can look like a cost shift, and — especially where the states are involved — they might want a say in the degree to which that cost shift occurs,” Quinn continued.
Another suggestion is to cap interconnection cost estimates at an early stage in the interconnection process, as CAISO is doing. “If the interconnection customer can get some information on cost that can feel firm, the interconnection customer can keep moving on,” Quinn said.
Panelist Mason Emnett, a federal regulatory attorney for NextEra Energy, had his own wish list. He said he would like RTOs to provide developers with information on their overloaded facilities. “Our transmission engineers can use that to go back to developers to give them a reality check and say, ‘This is what you’re facing.’”
Storage
Emnett also called for refinements in the modeling of storage resources. “RTOs generally consider the storage to be operating at full output — full discharge — at the worst time of the system, which generally is not going to be the time that the storage asset is operating that way.”
But he said storage doesn’t need an entirely separate process, either. “Nobody really loves [the current process]. The TOs don’t, the RTOs don’t, the generators don’t. But I’m not sure how you come up with a different one for storage because the question that’s being answered is largely the same: Are you changing the nature of the flows on the system? And what [is] the technical configuration of the equipment that you’re interconnecting and how does that interact with other things?”
Emnett said RTOs should provide more flexibility, praising MISO’s “net zero” policy.
“We’ve put some batteries on existing wind sites that had excess interconnection rights so that interconnection rights had already been studied at a certain level but they weren’t being fully utilized. In our mind, why can’t you just stick another resource on? You don’t have to go through the full study because all you’re using is something you’ve already got.”
He also cited PJM policy allowing interconnection customers to install more capacity than it has in injection rights. The interconnection service agreement requires that the customer limit its output. “If you burn down my wires you are responsible for everything,” Emnett said, summarizing.
Even if it requires a special protection scheme, Emnett said, “it’s going to be, in all likelihood, less expensive than upgrades and able to be implemented much more timely than the two and a half years to get a 10-MW storage project” approved.
The panel also discussed whether the commission should order more standardization in the grid operators’ interconnection processes.
“I hope FERC will allow regional differences,” said panelist Tim Aliff, MISO’s director of reliability planning. He noted the RTO operates in 13 states. “So we have 13 different opinions of how things should be done.”
Aliff also responded to Invenergy’s description of interconnection timelines. “I do take exception to the [assertion that MISO takes] ‘no less than three years’ because it depends on where you are in our footprint,” he said.
In March, FERC rejected the RTO’s proposed changes to its queue process, saying they assumed the current backlog could be blamed on “speculative” projects and “fail[ed] to consider other potential factors” (ER16-675). The commission also said a proposed milestone payment could create barriers to entry for smaller developers. (See MISO Queue Changes on Hold Pending Technical Conference.)
Aliff said that in addition to working on revisions to its proposal, MISO is considering how it can accommodate additional wind growth.
In 2011, MISO approved multi-value projects (MVPs) designed to serve 26 GW of wind. The RTO has 15 GW of installed wind and another 10 GW in the queue.
“So if all of this generation were to interconnect and actually start generating, then we would be at the capacity or close to the capacity of our MVPs,” he said. “So now we’re kicking off the process to say what’s the next step in this? We may or may not come out with MVP-like projects, but we want to get ahead of [the demand] again. We want to look at what the Clean Power Plan is going to do.”
Del Mar became the second city in San Diego County — after San Diego — to announce an objective of moving to 100% renewable energy by 2035. That goal is part of a larger climate action plan to reduce the city’s greenhouse gas emissions.
The oceanfront city hopes to encourage regional utility San Diego Gas and Electric to fully switch to renewable energy by that year, but it is also considering working with neighboring towns to create a community choice aggregator that would serve residents who opt to switch electricity providers.
Owners of gas-fired power plants are warning that they will be forced to shut down their units if the state doesn’t support their need for long-term contracts to maintain operations.
The plant owners argue their units are needed to ensure reliability on a grid that is increasingly subject to intermittent output from cheaper renewables.
A glut of natural gas and a boom in solar has driven wholesale power prices to unexpectedly low levels, threatening the viability of relatively modern gas-fired facilities.
In the latest chapter in their ongoing dispute, the City of Boulder and Xcel Energy are discussing a possible settlement that would end the city’s push to form a municipal electric utility.
The city’s bid to municipalize has not ended just yet, however. Boulder will continue to work on its application to the state Public Utilities Commission to acquire certain Xcel facilities and create its own utility, while also engaging in settlement talks with Xcel. A proposed settlement could come before the City Council this summer, and a new franchise agreement requiring voter approval could be placed on the November ballot.
To date, the city has spent more than $10.4 million on its municipalization bid, about $8 million of which came from the Utility Occupation Tax approved by voters in 2011, which generates about $1.9 million in revenue a year.
The $12 billion merger between Southern Co. and AGL Resources, which would create the second largest utility in the U.S. by customer count, has cleared another hurdle, receiving approval from the Commerce Commission
AGL is the parent company of Nicor Gas, which has 2.2 million customers in the state. The companies expect to complete the merger by the end of the year.
Company Challenges Archeologist over Burial Ground
Doershuk
Energy Transfer Partners says State Archeologist John Doershuk overstepped his bounds by recommending the company reroute its Dakota Access Pipeline to avoid land that Native Americans say is a sacred burial ground.
ETP said that a 2004 survey of the same land by the same archeologist “cleared the property we are crossing of any historic archeological sites.” It said Doershuk’s jurisdiction is over human remains only if they are 150 years old or older, and even then, he can only oversee their relocation and handling.
The Utilities Board granted permission for construction to start where the company already has landowners’ permission, but the state Department of Natural Resources issued a stop-work order based on Doershuk’s findings.
A coalition of business owners and nonprofit groups are urging the Public Utilities Commission to take a slower approach to major changes in net metering compensation to solar power owners.
In April, the Legislature narrowly defeated a bill that would have changed how behind-the-meter solar is credited, which put the issue in front of regulators.
More than two dozen businesses and environmental groups sent a petition Thursday requesting that the PUC give lawmakers and stakeholders more time to continue working on the issue in order to make sure that changes do not affect existing net metering customers and destabilize the rooftop solar industry.
The staff of the Public Service Commission is advising against a microgrid pilot plan by Baltimore Gas and Electric.
BGE has applied to build two public-purpose microgrids, each with a capacity of 2 to 3 MW. It would recover the $16.2 million cost through a customer charge.
The PSC staff questioned the legality of utility-owned microgrids and is asking the commission to take a larger look at the state’s microgrid policies.
The House of Representatives approved legislation that would require utilities to solicit long-term contracts for 1.2 GW each of Canadian hydroelectricity and offshore wind.
Supporters say the measure is a critical step in reducing greenhouse gas emissions and replacing energy that has left or will be leaving the New England energy grid in the coming years, including the scheduled 2019 shutdown of the Pilgrim nuclear power plant in Plymouth.
Some environmental activists say the House bill doesn’t go far enough in promoting renewable energy, while power generators say it interferes with the development of energy markets. (See Massachusetts Clean Power Bill Hit from All Sides.)
Battle Creek police arrested Joshua Buchanan on Thursday in connection to a firebomb found by workers at a Consumers Energy substation the day before.
Police did not provide any other information about Buchanan or the arrest. The Battle Creek Bomb Squad spent several hours at the substation removing a “crude incendiary device” and two gasoline cans. Sgt. Troy Gilleylen said the potential explosive device was not very sophisticated. The FBI is assisting in the investigation, and Buchanan could face terrorism charges.
“If this was put together properly it could have caused a lot of issues,” Gilleylen said. “These items were found inside a fenced area and under some heavy electrical equipment that routes power through Battle Creek.”
The Public Service Commission has fined Consumers Energy $515,800 over failing to provide thousands of its ratepayers with accurate meter readings.
Regulators announced the fine after an investigation into the company’s practice revealed the utility was violating rules for estimated billing. The PSC said Consumers lacked efficient monitoring, controls and customer communications.
The PSC said Consumers Energy improperly relied on usage estimates for more than a year for 12,671 customers. The fine represents about $200 for each customer whose usage was estimated in the past 16 months.
Public Service Commission staff have asked the commission to intervene in Great Plains Energy’s acquisition of Westar Energy, citing a 15-year old agreement in which Great Plains agreed to get PSC approval if it wanted to acquire a public utility.
The agreement stems from Great Plains’ purchase of Aquila in 2001. Great Plains countered that the agreement only applies to the purchase of utilities in the state. Westar is based in Kansas.
After utilities made an unsuccessful push to dramatically overhaul the state’s regulatory framework last legislative session, the Public Service Commission is moving to explore a “middle ground” on the way it oversees them.
The commission voted to open a case to bring together utilities, consumer groups and other parties in the hopes of brokering a conversation outside of the legislature. The move comes after the utilities’ failed effort to reduce the PSC’s discretion over setting rates and approving utility expenses.
Electric utilities said they need faster reimbursement to incentivize investment in aging infrastructure, but consumer groups countered the changes are unnecessary.
Coal production in the state declined by nearly a third during the first four months of 2016, with coal companies producing 4 million fewer tons so far this year.
The decline in demand was caused by the mild winter weather and utilities switching fuel sources, said Bud Clinch of the Montana Coal Council. Lower sales volume and lower coal prices may reduce tax revenues by as much as $25 million, he said.
A Nebraska wind-energy producer has asked state courts to force three public power entities to disclose their generation costs.
Aksamit Resource Management filed the action in three counties where it is building wind projects. Ratepayers “should know the costs and revenues associated with their publicly owned and operated public power districts,” CEO Gary Aksamit said. “When we get this information, we plan to share it with all Nebraskans so they can better understand why their electric rates have increased so much in recent years.”
The Nebraska Public Power District and the Omaha Public Power District say the information amounts to trade secrets and may be kept confidential, while the Municipal Energy Agency of Nebraska says it has provided sufficient information already.
The Antelope County Board of Supervisors approved a plan by Invenergy to erect 160 wind turbines. The supervisors imposed several conditions on the project, such as increased setback distances and completion of a noise analysis within 24 months after the structures are erected.
Eight turbines in the original proposal were dropped because of potential conflict with flight space around the Neligh airport.
A local protest group has re-formed to oppose Jersey Central Power & Light’s proposal to build a $75 million transmission line between Aberdeen and Red Bank. The same group successfully fought the same transmission line project in the 1990s.
Residents Against Giant Electric said it is concerned about the proposal’s effect on property values, health risks and aesthetics.
JCP&L’s Monmouth County Reliability Project consists of a 230-kV line that would run 10 miles along a commuter railroad.
The state Court of Appeals has ordered the Utilities Commission to revisit its decision to require environmental activists to pay a multimillion-dollar bond in order to appeal the commission’s approval of a Duke Energy power plant near Asheville.
The commission will hold a hearing on June 17 to reconsider its decision to require activist groups NC WARN and The Climate Times to put up a $10 million bond to pay for the cost of potential delays to the $1.1 billion project should their appeal be unsuccessful. Duke had asked for the bond amount to be set at $50 million.
The activists argued that requiring such a high bond was, in effect, blocking them from access to the appeal process.
The Public Service Commission spent 10 hours last week listening to testimony and comments regarding NextEra Energy’s proposed 72-turbine, 150-MW Brady Wind Energy Center II.
If approved, the $250 million project in Hettinger County will adjoin the proposed 87-turbine Brady Wind I wind farm in neighboring Stark County to the north. Brady Wind I and Brady Wind II could be online as soon as December, NextEra said.
If construction is not finished by December and the turbines aren’t operational, NextEra will be fined by Basin Electric Power Cooperative for not fulfilling its end of a power purchase agreement.
The nominating council for the Public Utilities Commission has selected nine candidates from the 19 who applied for the vacancy left by outgoing Chairman Andre Porter.
The council selected Edward Hess, Dave Hall, M. Howard Petricoff, Sam Gerhardstein, Lawrence Friedman, James Teitt, Andrew Thomas, Mark Ward and Gregory Williams for consideration. The council will interview the candidates on June 16.
The names of four finalists will then be forwarded to Gov. John Kasich for the final decision. Sierra Club activist Daniel Sawmiller, who led the opposition against FirstEnergy’s proposed power purchase agreements, did not make the cut.
A state task force is likely to recommend ways that legalized indoor marijuana growers can economize on their intensive use of energy and water rather than impose any limits on the booming horticultural business.
The panel is set to report to the legislature later this summer, likely proposing a new certification process that would encourage growers to conserve resources and suggest ways the state can provide education on the subject. Energy experts are concerned the growing demand from pot growers will require adjustments in the power grid.
The new industry, which became legal in October, is interested in energy efficiency but says best practices have not been established and information is not widely available.
Daniel J. Mumford, who spent 26 years with the Public Utility Commission’s Bureau of Consumer Services, has been appointed director of the Office of Competitive Market Oversight. Mumford most recently helped direct the commission’s investigations into the state’s retail electric and natural gas markets and formulate changes in the wake of the polar vortex of 2014.
“Those regulatory changes served consumers well by enhancing supplier disclosure requirements, strengthening consumer protections and reducing the time needed to switch suppliers,” PUC Chair Gladys M. Brown said. “As Pennsylvania’s markets continue to evolve, we are pleased to have Dan at the helm leading OCMO.”
Megan G. Good, an analyst with the PUC’s Bureau of Technical Utility Services, will become the OCMO deputy director.
The House of Representatives voted 64-7 to approve a bill intended to block a $700 million natural gas-fired power plant proposed in Burrillville.
The bill would require any tax agreement that the Burrillville Town Council reaches with developer Invenergy to be voted on in a town-wide referendum. Invenergy and its supporters, which include construction unions and business groups, say the legislation could lead to similar efforts to block infrastructure projects in other communities.
About half of the plant’s 900-MW capacity was successfully bid into the ISO-NE’s Forward Capacity Auction for delivery year 2019/20.
Prices in Deregulated Markets Still Higher than Regulated
Consumers shopping for electricity in the state’s deregulated market in 2014 paid more on average than those without choices, though the price disadvantage was smaller than in years past, according to a new study.
Residential power prices in deregulated markets, which cover about 85% of Texas, averaged 15.5% higher than those in regulated areas, where consumers cannot choose their providers. But the difference between the two markets has been shrinking in recent years. Statewide, power prices are below the national average.
The study was conducted by the Texas Coalition for Affordable Power, which advocates for cities and other local governments and negotiates their power contracts. It analyzed federal data on residential prices stretching back to 2002, the first year most of the state was deregulated.
State Expecting ‘Bumper Crop’ of Solar Farms this Summer
At least 20 “community solar” farms are scheduled to either be built or come online this summer in the state, according to industry insiders at last week’s Solar Power Southwest Conference.
The state is expected to have 14 GW of solar projects on the grid, but most of the focus has been on utility-scale and rooftop projects. Under community solar programs, homeowners in single-family dwellings can purchase individual solar panels on a farm and receive credits on their monthly light bills based on production.
Advocates say that community solar fills in the gaps by allowing renters and those homeowners restricted by covenants or with large shade trees on their property to purchase panels at these off-site, third-party solar farms to take advantage of those credits.
FAA Signs off on 86-Turbine Wind Farm in Chapman Ranch
The Federal Aviation Administration ruled that 86 wind turbines planned for Chapman Ranch, near Corpus Christi, won’t be hazardous for air navigation, clearing a significant hurdle for the proposed wind farm’s developer, Apex Clean Energy.
The agency conducted separate studies for each individual wind turbine that evaluated the structure and its impact on air traffic. Analysts concluded that each would present no hazard to air navigation, provided that the wind turbines have markings and lighting as stipulated.
The Corpus Christi City Council adopted a resolution in 2014 opposing the proposed wind farm. That position hasn’t changed, said Tom Tagliabue, the city’s director of intergovernmental relations. The council voted later that year to annex 16 square miles of Chapman Ranch in hopes that it would halt the project, but Apex said the turbines are not planned for construction in the city-annexed land.
Gov. Peter Shumlin vetoed a bill giving communities more say in the siting of wind and solar power projects.
Shumlin said he supported the parts of the bill giving towns and regional planning commissions more input in the siting of energy projects, but he objected to the tighter standards for noise from wind turbines. The standards effectively would “make Vermont the first state in the country to declare a public health emergency around wind energy, without peer-reviewed science backing that assertion up,” the governor said in his veto message.
The governor’s other objections included language on solar energy that he said could create a problem with deeds when properties are sold, and a lack of funding for regional planning commissions to do new energy planning work.
DEQ Issues Permits for Dominion’s Ash Pond Draining
The Department of Environmental Quality issued a draft of a permit that would allow Dominion Virginia Power to drain up to 5 million gallons of coal ash pond water a day into the James River. The permit is one of four the company will need to begin draining the impoundment at Chesterfield Power Station.
The company is under federal mandate to drain the ash ponds at Chesterfield and Bremo Bluff Power station. Environmental groups won a legal challenge to the company’s first efforts at Bremo, and they vow to study the permit to make sure it meets the necessary standards.
The state will accept written comments about the permit through July 21.
Foes of the proposed Atlantic Coast and Mountain Valley pipelines, assisted by veterans from the anti-Keystone XL Pipeline effort, planted corn in the paths of the two projects in Franklin. They hope the “Seeds of Protest” will grow into a symbolic barricade of the shale-gas pipelines.
“I have children and grandchildren and I want them to grow up in a world with clean water, clean air and healthy food to eat,” said Mekasi Horinek Camp, a member of the Ponca Tribe, who joined in the protest. “Anything that threatens Mother Earth threatens my children and grandchildren.”
The Madison City Council adopted a measure last week to cut the city’s emissions 80% by 2050.
The plan creates an inventory of city-owned property that could house rooftop solar and establishes the Property Assessed Clean Energy (PACE) program to assist property owners in financing energy upgrades. The city has also committed to creating permanent energy staff positions and reviewing its climate change plan.
The plan also recommends the city obtain a quarter of its electricity from clean sources by 2025 and half by 2030.
Solar advocates have asked legislators to back a proposal lifting the 25-kW cap on solar installations eligible to sell surplus power back into the grid, expanding the practice of net metering to larger projects. Supporters hope the measure will boost commercial solar installations and create jobs as the state confronts the declining fortunes of its oil, gas and coal industries.
The measure is expected to meet opposition from utilities, including PacifiCorp, which last month told state lawmakers the practice amounted to paying subsidies to homes and businesses with solar panels.
Beginning this year, Capacity Performance units no longer would be compensated for participating in cold weather testing, which is set to be continued under a plan that the PJM Operating Committee will be asked to endorse in August.
The program is voluntary, noted PJM’s David Schweizer, and generators may self-schedule their own testing.
As PJM moves to a Capacity Performance model, designed to avoid the outages experienced during the Polar Vortex, the RTO wants to continue winter testing but end generator compensation.
The rationale behind the change, which was first mentioned in April, is that PJM expects generators to factor the cost of testing into their offers. (See “Plan: Continue Cold Weather Testing, End Compensation for CP Participants,” PJM Operating Committee Briefs.)
All units will be required to be Capacity Performance beginning in the 2020/21 delivery year.
There were no other changes recommended for the program, which Schweizer said was valuable even though it didn’t yield much useful data last winter because of warmer temperatures.
Several members representing generation said the testing program will be a tough sell absent compensation.
“Without compensation, the program will dry up,” said one stakeholder who asked not to be identified.
John Farber of the Delaware Public Service Commission supported the plan.
“Customers are paying for premium capacity. The question is if they’re getting it,” he said. “We support where PJM is going with this. We really think compensation should be covered through the CP offer.”
Committee Chair Mike Bryson said staff would incorporate members’ comments into revised manual language that will be brought to a first read in July.
PJM Won’t Ask FERC to Rehear Ramp Rate Proposal, Plans to Collect Data
The Tariff changes would have exempted a capacity resource from nonperformance charges if it was following PJM’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. They were drafted as a temporary measure to guard against generators self-scheduling prior to a PAH.
“As of right now, it’s status quo,” said PJM’s Rebecca Stadelmeyer, who convened a number of lengthy discussions over the past few months to win stakeholder consensus. “You need to be at expected Capacity Performance immediately.”
“We have decided internally that we’re not going to request a rehearing, largely because we took a good look at the arguments using examples we had from stakeholder endorsement,” Bryson said. “I think data is the next cog in getting this done. We’ll continue to collect that. I don’t know if we necessarily need an emergency situation to get all the data, though a performance assessment hour would help.”
Stu Bresler, senior vice president for operation and markets, agreed.
“We were disappointed that FERC didn’t take our word for it, but it seems the only thing that will change their minds at this point is data,” he said.
GOs to be Questioned on Governor Response Survey Results
PJM is concerned that most units participating in PJM’s Governor Response Survey did not provide reasons for deviating from NERC settings.
Schweizer said staff would be reaching out to generation operators to better understand the survey results, including why 5% of units didn’t participate.
Of those responding, 76% reported they had a governor capable of changing output in response to changes in interconnection frequency; 69% said their governor was operational; and 53% responded that their governor was capable of operating with the settings recommended by NERC.
About 43% of combustion turbines, 29% of combined cycle units and 24% of steam/fossil units reported they were capable of providing frequency response in accordance with NERC guidelines. Only 8% of hydro units and 1% of nuclear units reported such capability.
Two-thirds of the units did not provide a reason for deviation from NERC settings.
Among the reasons reported: control mode does not allow (10%); did not align with NERC-recommended dead-band (9%); and set with a slightly less droop setting of 4% (5%).
WASHINGTON — Four Ph.Ds. joined in a tag-team debate last week on the virtues of scarcity pricing versus capacity markets in a panel discussion-cum-economics seminar at the Energy Bar Association’s Annual Meeting.
It’s unlikely any of the combatants, who have often sparred each other, came away with any different opinions. But the repartee was no less sharp for the familiarity.
William W. Hogan, research director of the Harvard Electricity Policy Group, staked out the energy market-only pole of the debate, repeating his argument that capacity markets are unnecessary if the energy and ancillary services markets “get their prices right.”
“Life is too short to spend your time trying to perfect capacity markets,” Hogan said.
PJM Market Monitor Joe Bowring said Hogan’s vision is unrealistic. “It’s easy enough to say in a theoretical world that scarcity pricing should take care of everything. But we have yet to see that demonstrated in the real world,” he said.
Administrative Determinations
Bowring also attempted to puncture any notion that scarcity pricing is much simpler than capacity markets.
“Let’s not pretend that scarcity pricing is some automatic market mechanism that will simply take care of problems without an intervention,” he said. “It is equally administrative as capacity markets — just different. You still have to determine … the appropriate net revenue. And it’s a lot trickier than it sounds.”
Sam Newell, a principal with The Brattle Group, challenged Bowring’s assertion.
“Although the pricing in an operating reserve demand curve [ORDC] is administratively determined, actually there’s less administrative determinations than in a capacity market because you’re just saying what the prices should go to under certain real-time operating conditions.”
In a capacity market, he continued, “You have to decide what is the reliability concept you’re meeting. Is it summer peak? … You have to decide how different resources can qualify to meet that and so there’s a lot more administrative determinations.”
David Patton, whose Potomac Economics provides monitoring services in MISO, ISO-NE, NYISO and ERCOT, expressed concern over the volatility of generators’ revenue streams under scarcity pricing.
“Unless you’re willing to price shortages at $200,000/MWh, you’re not going to meet your planning requirements with the energy market alone,” he said.
“Shortage pricing is not like a capacity market where you’re going to get a level of revenue that might fluctuate by 10 to 20% a year. With shortage pricing, you might get 10 years of revenue in one year and then the other nine years the generators are going to think they’re going bankrupt.”
This is because shortage prices “increase exponentially when you get unusually hot weather and unusually high loads or unusually poor generator performance,” Patton said. “Look at ERCOT in 2011 and compare the number of shortage incidents you had in that year to the prior 20 years.”
That could lead to constant tinkering, Patton said. “You don’t want policymakers to jump in when it’s not producing revenues for a number of years. You also don’t want them to jump in in the year when it produces $20 billion of revenue,” he said. “Because that’s what you signed up for.”
Bowring added another potential negative consequence.
“What will happen if you go through eight years of very low revenues under scarcity pricing … and a significant number of units decide to retire because they can’t see into the future? They don’t know if [in] the ninth or 10th year there’s going to be $20 billion. They retire if the revenues aren’t adequate.
“There’s a level of risk associated with scarcity pricing that differs from capacity markets, which is why the optimum might be to have more revenues in the scarcity pricing but not 100% of expected revenues,” Bowring said.
Locational Issues
Bowring said he agreed with the need for scarcity pricing but said it “is done very ineffectively now” in PJM because the ORDC hasn’t been made “adequately locational.”
“Scarcity doesn’t work if it’s an aggregate, because you can be long aggregate in PJM or other big RTOs or ISOs and be very short in particular places,” he said.
Joint Optimization
ERCOT has a different problem, said Patton: a failure to jointly optimize the energy and shortage markets so that the ISO can price transitory shortages.
“We perpetually undercompensate units like pump storage units, combined cycle units. They’re way more valuable for reliability because they can ramp fast,” he said. “But if you don’t reveal the true state of the system in every five minutes you undercompensate them.”
Hogan sought to allay what he called a misconception that shortage pricing is incompatible with price caps and other market mitigation measures.
“The advantage of this operating reserve demand curve … is that prices go up because of the scarcity of reserves. They don’t go up necessarily because of high offers by the generators. So it is completely compatible to have offer caps — which are dealing with market power problems with generators — that are set by their variable cost of operation. You could have a $500 offer cap, say, on generators and then you have the operating reserve demand curve that is setting the price and the price is $3,000/MWh.
“All of the market mitigation … continue to exist. You don’t have to get rid of that,” he continued. “If you don’t have the operating reserve demand curve, offer caps depress the price and do all kinds of bad things.”
Changing Conditions
Newell said scarcity pricing may be better suited to respond to changes facing the industry.
“With variable energy resources suppressing energy prices — creating over-generation sometimes on the one hand, ramping shortages on the other — the nature of reliability is changing, and it’s not just about summer peak.
“And that is another reason why I want to second what Dr. Hogan said. It is better to get the prices right — reflecting real-time conditions and telling the market what you need, when you need it — rather than just having a narrow administrative idea of reliability. So I would like to see more money moving into the energy and ancillary services markets and out of the capacity markets.”
SPP staff told the Seams Steering Committee, which met in Dallas on June 8, that the MISO members of the Interregional Planning Stakeholder Advisory Committee (IPSAC) voted last month to pursue the study. The Joint Planning Committee, composed of SPP’s David Kelley, director of interregional relations, and MISO’s Eric Thoms, manager of planning coordination and strategy, made it official May 31 when the two agreed to begin the study.
Government subsidies make renewable energy projects less risky investments. But the IEA warns that as the energy generated by renewables becomes less expensive, governments may look to scale back the subsidies.
Scientists working in Iceland are testing a new method of carbon capture and sequestration, injecting CO2 from a geothermal plant into basalt to form calcite, theoretically locking the gas in the ground permanently.
Developers rushing to meet a deadline for a federal solar tax credit are driving U.S. solar installations to nearly double the total capacity in 2016, according to a report by GTM Research. By the end of the year, 14.5 GW of solar capacity will be online, the report says.
FERC has granted the request for new hearings on Transco’s Garden State Expansion project after a group of municipalities said the company failed to give proper notice of meetings and didn’t meet environmental requirements.
The Nuclear Regulatory Commission held its annual public meeting on the operation of Entergy’s Indian Point nuclear station, and things got heated, with members of the public telling the commission it is failing in its job to keep the plant operating safely.
Talen Energy, operator of the Susquehanna nuclear plant in Pennsylvania, reported the discovery of two small leaks of radioactive water while shutting Unit 1 down last week for regular maintenance.
Del Mar became the second city in San Diego County — after San Diego — to announce an objective of moving to 100% renewable energy by 2035. That goal is part of a larger climate action plan to reduce the city’s greenhouse gas emissions.
In the latest chapter in their ongoing dispute, the City of Boulder and Xcel Energy are discussing a possible settlement that would end the city’s push to form a municipal electric utility.
The $12 billion merger between Southern Co. and AGL Resources, which would create the second largest utility in the U.S. by customer count, has cleared another hurdle, receiving approval from the Commerce Commission
The House of Representatives approved legislation that would require utilities to solicit long-term contracts for 1.2 GW each of Canadian hydroelectricity and offshore wind.
Battle Creek police arrested Joshua Buchanan on Thursday in connection to a firebomb found by workers at a Consumers Energy substation the day before.
The Public Service Commission has fined Consumers Energy $515,800 over failing to provide thousands of its ratepayers with accurate meter readings.
Coal production in the state declined by nearly a third during the first four months of 2016, with coal companies producing 4 million fewer tons so far this year.
The Antelope County Board of Supervisors approved a plan by Invenergy to erect 160 wind turbines. The supervisors imposed several conditions on the project, such as increased setback distances and completion of a noise analysis within 24 months after the structures are erected.
A local protest group has re-formed to oppose Jersey Central Power & Light’s proposal to build a $75 million transmission line between Aberdeen and Red Bank. The same group successfully fought the same transmission line project in the 1990s.
The state Court of Appeals has ordered the Utilities Commission to revisit its decision to require environmental activists to pay a multimillion-dollar bond in order to appeal the commission’s approval of a Duke Energy power plant near Asheville.
The Public Service Commission spent 10 hours last week listening to testimony and comments regarding NextEra Energy’s proposed 72-turbine, 150-MW Brady Wind Energy Center II.
The nominating council for the Public Utilities Commission has selected nine candidates from the 19 who applied for the vacancy left by outgoing Chairman Andre Porter.
A state task force is likely to recommend ways that legalized indoor marijuana growers can economize on their intensive use of energy and water rather than impose any limits on the booming horticultural business.
Daniel J. Mumford, who spent 26 years with the Public Utility Commission’s Bureau of Consumer Services, has been appointed director of the Office of Competitive Market Oversight. Mumford most recently helped direct the commission’s investigations into the state’s retail electric and natural gas markets and formulate changes in the wake of the polar vortex of 2014.
The House of Representatives voted 64-7 to approve a bill intended to block a $700 million natural gas-fired power plant proposed in Burrillville.
The Federal Aviation Administration ruled that 86 wind turbines planned for Chapman Ranch, near Corpus Christi, won’t be hazardous for air navigation, clearing a significant hurdle for the proposed wind farm’s developer, Apex Clean Energy.
Gov. Peter Shumlin vetoed a bill giving communities more say in the siting of wind and solar power projects.
The Madison City Council adopted a measure last week to cut the city’s emissions 80% by 2050.
Bowring also attempted to puncture any notion that scarcity pricing is much simpler than capacity markets.
