RENSSELAER, N.Y. — The NYISOReliability Needs Assessment for 2017-2026 identified two transmission security needs beginning next year.
The assessment, which was approved by the Management Committee on Wednesday, identified the risk of thermal overloads on New York State Electric and Gas’ Oakdale 345/115-kV transformer in the Binghamton area and the Long Island Power Authority’s East Garden City-Valley Stream 138-kV line. Generation resources were deemed adequate in the period.
The Oakdale transformer overload was also mentioned in the 2014 assessment. NYSEG responded with plans for a third Oakdale transformer and reconfiguration of the Oakdale 345-kV substation. However, NYSEG has since updated the in-service date of the improvements from 2018 to the winter of 2021, the report said.
The LIPA 138-kV line has a risk of thermal overloads under N-1-1 conditions. “The power flow on this facility is driven by the combination of LIPA load in western Long Island and the scheduled 300-MW wheel between ConEdison and LIPA,” the report said.
Following the NYISO Board of Directors’ approval of the assessment, NYSEG and LIPA will be asked to develop solutions for the two transmission needs. If they are not addressed in their updated Local Transmission Owner Plans, the ISO will solicit solutions from developers.
The proposed solutions will be evaluated in the 2016 Comprehensive Reliability Plan. The RNA is the foundation for the reliability plan, which will be adopted next year.
Until upgrades can be completed, “the use of demand response and operating procedures, including load shedding under emergency conditions, may be necessary to maintain reliability during peak load periods,” the ISO said.
The biennial RNA process assumed the deactivation of the R.E. Ginna and James A. FitzPatrick nuclear plants. Those potential retirements were announced since the last Comprehensive Reliability Plan in 2014.
The plants, with a combined 1,463 MW, may be saved by the Clean Energy Standard adopted by the state’s Public Service Commission in August, which would pay upstate nuclear plants nearly $1 billion for their carbon-free attributes in the first two years of the program.
Systemwide Demand Response Activated
A summer heat wave prompted the first mandatory systemwide DR event in NYISO in three years.
The Aug. 12 event came on the second day of a two-day heat wave, when the peak load was 31,477 MW. NYISO estimated a peak of 32,415 MW if DR had not been activated.
Actual loads were 1,000 MW more than earlier projections for the day and came as neighboring control areas in Ontario and New England were also experiencing high demand. Operating reserves for some time intervals fell below the required 2,620 MW.
The summer’s peak was 32,076 MW on Aug. 11.
“The peak represented the third consecutive year that the NYISO peak fell below the 50/50 forecast,” said Wes Yeomans, NYISO’s operations vice president, who presented the summer 2016 report. The forecasted 50/50 peak was 33,360 MW.
Noteworthy over the two days was the performance of the state’s 1,700 MW of wind resources.
On Aug. 11, wind generation was essentially a flat line of about 50 MW from 8 a.m. to 8 p.m. On Aug. 12, as thunderstorm alerts began to move through the state, wind generation topped out at about 600 MW during the afternoon, closely following the rise in demand, which peaked in the 4 p.m. hour.
On July 24, NYISO activated its 21-hour notice for DR for the Lower Hudson Valley, New York City and Long Island, but the ISO did not implement its operation. Rochester Gas & Electric, Con Ed and the New York Power Authority instituted their voluntary DR programs, however.
The last systemwide DR event was during the polar vortex in January 2014 when the voluntary program was activated. The last mandatory DR systemwide event was in July 2013.
SAN DIEGO — Transmission industry owners, operators, generators, regulators, financiers and other key players from the Western U.S. attended Infocast’s 8th annual Transmission Summit West last week. They discussed the strategic, regulatory, investment and technology issues facing the industry.
Western Regionalization
CAISO’sStacy Crowley, vice president of regional and federal affairs, pushed the benefits of ISO participation in her solo presentation, saying, “Utilities and stakeholders have found these ISOs to be valuable, as far as providing cost-effective power.
“We know in the Midwest, states like Iowa could not have reached their renewable standards without an ISO. We’ve seen entities around the Northwest asking if there are efficiencies with a larger market. Clearly, a board appointed by the California governor and approved by the State Senate would not fly in a regional ISO. California clearly has the largest load of any state in the West, but a regional ISO must speak for everyone and their policies.”
ColumbiaGrid CEO Patrick Damiano agreed, but he made the case that coordinating planning doesn’t require a centralized market.
ColumbiaGrid conducts transmission planning and other coordination for its eight members: Avista, Bonneville Power Administration, Chelan County Public Utility District, Grant County PUD, Seattle City Light, Snohomish County PUD, Tacoma Power and Puget Sound Energy, which joined the Western Energy Imbalance Market on Oct. 1.
“The Northwest has always been an active bilateral market,” Damiano said.
“We’ve been very excited about the creation of the EIM,” said Gerald Deaver, manager of regional transmission policy for Xcel Energy. “Our first baby step was FERC’s approval of a joint dispatch area in Colorado [with Platte River Power Authority]. We’ll be the market operator, but we look at it as a way to more efficiently use generation resources in the balancing area. Our ultimate goal is to develop a larger geographic footprint to better integrate renewables. Our hope is that entities will become more comfortable operating in that environment.”
“I can’t imagine all of the West as we know it today would be one RTO. It’s too big. I see two or three RTOs with seams agreements,” SouthWestern Power Group’s Tom Wray said. “For resource management and market efficiency, [RTOs] are clearly a good policy move for the country. One of the motivating factors for expansion of the regional market we know as Cal-ISO is largely coming from regulatory pressure.”
Tanya Bodell, executive director of Energyzt, called for “market-based solutions” to cope with too much generation on the Western system. “West Texas retailers are selling energy for free on nights and weekends. FERC Order 745 has opened up an opportunity for demand to come into the market. I can see 745 creating a mechanism through which system operations encourage people and pay people to use more energy. Generators have a different bid price to operate, versus a bid price to curtail. You may end up getting a curtailment market, where the ISO asks for bids from generators.”
Renewable Integration Remains Sticky Issue
“We’ve done pretty well so far in integrating renewables. We didn’t think 20% would be that easy, but it turned out to be not so much of a challenge,” said Carl Zichella, director of Western transmission for the Natural Resources Defense Council. “We have 38 different balancing authorities in the West. It’s one big grid operating in discrete chunks, rather than an integrated system. While that’s worked so far, we’re going to need to do much better to integrate deeper penetration of wind.
“The worst-case scenario for renewables is what we have now … [balancing authorities] complicating the use of transmission with bilateral contracts and artificial congestion. The biggest hurdle to regionalization is the governmental structure.”
Jay Caspary, SPP’s director of research, development and Tariff studies, said America’s best renewable resources straddle the seam between the Western and Eastern interconnections. While SPP, MISO and ERCOT have built and continue to build transmission to access those resources, the abundance does create a dilemma.
“ERCOT is harvesting thousands of megawatts in SPP’s backyard and pulling them into ERCOT,” he said. “We have two separate independent networks in the Texas Panhandle. At some point, we’ll probably have to integrate those two, but there are a lot of jurisdictional issues.”
In California, rooftop solar is the oncoming train. Jack Moore, director of market analysis for Energy + Environmental Economics, said his company is projecting the state will enjoy 17 to 23 GW of the sunshine resource by 2025. “The big driver we see is in certain hours, California has more solar than it can use. That does set up a reason for [increased] transmission to be able to bring more flexibility to the system.”
“Our experience in Texas is that you build these [interconnection] ties and they get oversubscribed,” said Bill Bojorquez, vice president for Hunt Power. “There are great stranded resources in New Mexico. Sharyland Utilities has over 11 [GW] of generator-interconnection requests. We are literally over-subscribed. It’s one of those stories where if you build it, they’ll be oversubscribed.”
Getting Utilities to Embrace Alternative Technologies
Several speakers complained about the industry’s conservatism.
William White, director of public affairs for CTC Global, said his company has found it difficult winning acceptance of its high-temperature, low-sag, composite core conductors. “We’re in the odd position of having a proven product that works,” he said. “We know it works, our customers know it works, but old habits die hard. Most of [today’s] conductors are literally 100-year-old technology.”
“Some of the biggest resistance to regionalization is the cost,” said Gregg Rotenberg, president of Smart Wires, which provides “grid optimization solutions.”
“If we’re having a conversation about regionalization and we’re only using existing infrastructure, that means we’re using the grid inefficiently,” Rotenberg said. “The hardest group to get involved is the transmission groups at these utilities. When we get them on an equal playing field and we’re spending less on new technologies, we’ll have a new grid.”
Byron Woertz Jr., the Western Electricity Coordinating Council’s manager of system adequacy planning, preferred to see his glass half full. “This a country that put a man on the moon with 20th century technology, so I think we can improve the grid,” he said.
Battery Storage Ready for Prime Time
Asked whether battery storage needs tax credits similar to wind and solar resources, Kiran Kumaraswamy, market development director for AES Energy Storage, said storage is “absolutely ready for prime time.”
“What we really need is a framework to value this class of resources. Four to five years ago, we started talking about the value of solar in a way in which you could bring all those benefits to the table and compare them with all the other options. The gap right now is being able to evaluate [storage] resources on an apples-to-apples basis.”
“I think energy storage works best when paired with other grid assets, to increase the value of the electricity being generated,” said John Jung, CEO of Greensmith Energy Management Systems. “You can do a lot more with electricity when you have the ability to shape the nature of it and the quality of it.”
John Fernandes, RES Americas’ director of policy and market development, said he is not worried about customer migration from the grid. “I’ve been announcing the death spiral of the utility death spiral for years now.”
Non-utilities “are not dealing with NERC violations worth millions of dollars a day,” he said. “When you’re talking about megawatts, [reliability] matters. We’re so highly dependent on this super-reliable service.”
Making FERC Order 1000 Work
A panel sharing their experiences with FERC Order 1000’s directive on competitive transmission projects agreed that CAISO continues to put space between itself and other RTOs with its implementation of the order.
“The evaluation process is certainly evolving. Cal-ISO maybe puts more emphasis on costs and less emphasis on [operations and maintenance], but it’s gotten much better,” said Charlie Adamson, principal manager of major transmission and distribution projects for Southern California Edison. “Every evaluation, they’ve gotten better at it. Things like the EIM or the ultimate experience of an ISO … opens up market availabilities for that energy transfer to make sense. Over time, that could enable long-haul lines that bring in energy from where it’s cheap to where it’s necessary.”
Josh Burkholder, director of transmission asset strategy and grid development for AEP Transmission and Transource Energy, relayed his experiences in SPP’s first competitive process, which resulted in one project being awarded — and then canceled as unneeded. “There were some real head scratchers [in how an industry expert panel graded the projects]. A notch difference in your parent company’s credit rating was a five-point difference [in the scoring]. In a $10 million project, [the credit rating is] pretty irrelevant. Be careful what you wish for a little bit, when it comes to clarity and understanding with how the decision is made.”
“From my standpoint, a lot of things that may not be apparent may become a reliability issues when it’s too late to solve the issue with transmission,” said Bob Smith, vice president of transmission development for TransCanyon, a joint venture of Pinnacle West Capital and Berkshire Hathaway Energy. “This is the second year we’ve had laws in California that are going to require a 50% [renewable portfolio standard], maybe higher, to comply with greenhouse gas laws. Yet, Cal-ISO is relying on a 20% portfolio? It doesn’t make sense for Cal-ISO to be planning when you don’t know where the resources are. By the time Cal-ISO gets clarity on where resources are, we’re coming pretty close to 12 years from the 2030 policy deadline, and you don’t develop transmission in three or four years.”
Speaking of transmission projects in general, Chris Jones, a vice president with Duke-American Transmission Co., said delays in the permitting process “that can happen over the decades-long process” remains “the biggest risk in each of our projects.”
“One of the things that’s changed since I started doing this work is the sensationalism of these projects and the media coverage you get and the protests that come with that. It’s usually local groups, but we’re seeing more and more groups outside the [non-governmental organizations] get media coverage. You’re seeing that now with the North Dakota pipeline project.”
Ali Amirali, a senior vice president with the Starwood Energy Group, called transmission development “a giant game of economic chicken.” He said, “The generation developers are waiting for the transmission to be built. The transmission developers want the generation to be built before getting into the heavy capitalization of transmission.”
California and Massachusetts tied for first place in the 2016 State Energy Efficiency Scorecard published by the American Council for an Energy-Efficient Economy. This is the sixth consecutive year that Massachusetts led the nation.
Missouri, Maine and Michigan were the most-improved states, according to the study. The study identified Louisiana, Kansas, South Dakota, Wyoming and North Dakota as the states most in need of improvement.
“States are spurring efficiency investment through advancements in building energy codes, transportation planning and leading by example in their own facilities and fleets. These investments reap large benefits, giving businesses, governments and consumers more control over how and when they use energy,” said ACEEE Executive Director Steven Nadel.
Utilities: Customers Subsidizing Rooftop Solar Homes
Arizona Public Service and the Salt River Project say that customers who have installed rooftop solar panels on their homes are increasingly burdening those who haven’t.
SRP recently told a local newspaper that its “demand charge” of about $50 on rooftop solar customers was necessary because they weren’t paying their fair share for the energy they consumed from the grid. APS said 96% of its customers pay more than they should because of state subsidies for rooftop solar installations. The utility is seeking a new rate plan from state regulators.
The solar industry in the state disputes these statements. SolarCity is suing SRP over the extra charge, while groups such as the Arizona Solar Energy Industries Association and Solar Strong America say the utilities are trying to undermine net metering in the state.
Water District Installing Largest Public Energy Storage System
The Irvine Ranch Water District is installing a 7-MW, 34-MWh energy storage system using Tesla batteries in what is billed as the largest network of energy storage systems at a public water agency in the U.S.
Irvine Ranch is working with Advanced Microgrid Solutions to install the battery storage system at three water treatment plants, a deep aquifer treatment system, a desalinization plant and six large pumping stations. The district decided on the system after regulators called on utilities and municipalities to install systems to provide power in the event of service interruptions.
“In a region challenged by the closure of the San Onofre Nuclear Generating Station,” Irvine Ranch said. The project will allow it to reduce demand from the grid when requested by the utility without curtailing water treatment operations.
Pacific Gas and Electric last week filed a response to public comments submitted to the Public Utilities Commission on its plan to retire its Diablo Canyon nuclear plant in 2025.
“We fully understand that elements of the joint proposal reflect important issues for the state and PG&E’s customers,” PG&E Electric President Geisha Williams said in a statement. “The near decade-long period ahead of us provides the time to plan and replace Diablo Canyon’s energy with new [greenhouse gas]-free replacement resources.”
The company, which reached a settlement over the plan with employees and environmental groups in August, said it did not expect rates to increase as a result of the closure.
Gov. Jerry Brown signed a bill last week that requires participants in energy efficiency programs for heating and air conditioning to provide proof that their equipment has been properly installed.
“Research shows that many of these projects are not being installed correctly, meaning customers aren’t receiving the energy efficiency savings they paid for and could even be dealing with a significant safety hazard,” said State Sen. Lois Wolk, the bill’s sponsor. Wolk said the bill would also help the state meet its goals to combat climate change.
Brown also signed a package of bills designed to increase transparency and public participation in Public Utilities Commission hearings and proceedings. The bills were written after the deadly explosion of a Pacific Gas and Electric natural gas pipeline revealed off-the-record, private communications between the commission and the companies it regulates.
Construction of a proposed NRG Energy power plant in Oxnard may be delayed after the company made some changes to its design, the state Energy Commission said at a public hearing last week.
NRG decided to change how the plant’s water discharge is routed. The commission said that means it will require more data from the company before it can give final approval to the plant, which has been sited at a local beach. A final staff report was expected by Oct. 14, but that may need to be pushed back, the commission said.
The plant, called the Puente Project, is intended to replace two aging generators in the area.
The Commerce Commission voted unanimously to accept Ameren Illinois’ plan to expand the installation of smart meters to its entire service territory.
Currently, just 330,000 of the company’s 1.2 million customers have smart meters installed. Ameren had originally planned to expand to just 62% of its customers, but the utility decided to expand the program once it found that the meters reduced outages and saved money for both it and its customers.
The Environmental Defense Fund and the Citizens Utility Board both supported the plan. Installations will be completed by 2019.
Former PUB Member: Hydro Customers Facing Giant Rate Hikes
An over-budget transmission project, coupled with increased charges from dam construction, could double rates for Manitoba Hydro customers, according to a former Public Utilities Board member.
Graham Lane, a former PUB chairman and chartered accountant, said mounting debts from the Bipole III transmission line project and the Wuskwatim dam could spur Manitoba Hydro to seek major rate hikes.
“The losses [associated with the projects] are going to be huge,” he said. “By my own calculations, by the time it all ends, Hydro will have lost somewhere in the area of $5 billion to $10 billion, and that money will basically have to be covered by the ratepayers.”
State officials released proposed fracking regulations last week that would ban drilling in three watersheds in Western Maryland and require four layers of steel casing and cement around wells to prevent water, gas and other fluids from migrating.
Environment Secretary Ben H. Grumbles called the proposed regulations “the most stringent” in the country. However, the rules would allow drill sites closer to homes and private wells than proposed by former Gov. Martin O’Malley (D).
The state legislature imposed a moratorium on fracking that is due to expire in October 2017. Environmentalists say they will try next year to make the moratorium permanent.
The Montana Environmental Information Center and Vote Solar filed a complaint with FERC claiming the Public Service Commission violated federal regulations when it suspended payments for energy projects while it reviews standard rates for small solar energy developers.
“That rate has now been taken off the table when projects were in their late stages,” said Brian Fadie, clean energy program director for MEIC. “It undercuts solar development in Montana at the moment.”
A hearing on new rates could come as early as January, PSC spokesman Eric Sell said.
A special legislative committee on climate change is seeking to create a statewide climate action plan — addressing issues such as solar energy and financing energy improvement.
“Some of the public power districts have created their own, what I would say, goals. Nebraska Public Power District, I think their goal is 10%,” state Sen. Ken Haar said. The districts’ goals “are fairly low compared to what other states are doing that actually have energy standards.”
Harr said the committee will issue a report to the Legislature by the end of the year.
Empire Center Critical of PSC’s Clean Energy Standard
The Empire Center for Public Policy has issued a report critical of the Public Service Commission’s Clean Energy Standard, passed in August, which calls for 50% of the state’s energy needs to come from renewable sources by 2030.
The think tank says that rather than subsidizing renewables, the PSC should set greenhouse emission standards and let utilities figure out how to meet them. The group, which promotes “free-market principles [and] personal responsibility,” also maintains that the cost of ramping up renewables will exceed the $2/month rate increase that the commission predicted and that it underestimated the difficulty of switching to solar and wind power.
PSC spokesman Jon Sorensen defended the plan. “Rather than support bold national leadership to combat the very real threat of climate change, this right-wing think tank denies reality and relies on bogus cost assumptions to argue for inaction,” Sorensen said in a prepared statement.
Long Island has seen a 320% growth in solar energy over the past four years and just completed its 35,000th solar energy project, Gov. Andrew Cuomo announced.
Long Island, which is part of NY-Sun, the $1 billion initiative launched by Cuomo to advance the solar industry and create jobs, now saves 200,000 tons of carbon emissions per year.
“Clean energy is our future, and Long Island is leading the state in growing our clean tech economy and achieving our climate change goals,” Cuomo said.
Two Sides Clash over Environmental Justice Reports
State regulators and environmentalists are clashing over reports that say new coal ash landfills at Duke Energy’s Sutton Plant in Wilmington and Dan River plant in Eden won’t unfairly affect anyone based on age, race, income or language.
The findings were the first two environmental justice reports issued by state regulators since announcing in April that they would start requiring environmental justice reviews before issuing permits.
Therese Vick, a community organizer with the Blue Ridge Environmental Defense League, said the reviews are not worth much because there is no mechanism to deny a permit on environmental justice grounds. “It’s an empty process,” she said.
Duke Energy Progress is seeking to build a new 230-kV transmission line in Bladen County that would connect Innovative Solar’s new 40-MW solar power facility in Bladen County to Duke’s existing Cumberland to Delco 230-kV transmission line in Bladen County.
In its September application filed with the Utilities Commission, Duke said it will build a 230-kV breaker station adjacent to a new substation that Innovative Solar plans to build adjacent to the Cumberland to Delco 230-kV line.
The Power Sitting Board has given approval to Boston-based Advanced Power Services for a $1.1 billion, 1,105-MW natural gas-fired power plant in eastern Ohio.
The plant is expected to begin operating in January 2020.
Kasich Threatens Veto of Any Bill Killing Clean Energy Standards
Kasich
Gov. John Kasich threatened to veto any legislation eliminating standards for renewable energy and energy efficiency, which could be a bad sign for proposals pending in the General Assembly.
Two years ago, Kasich placed a freeze on standards requiring electricity utilities to meet annual benchmarks for renewable energy and to help customers reduce energy use. The freeze will expire soon, and not all lawmakers would like to see it extended.
Pacific Power announced last week that four solar power projects in central and southern Oregon from which it acquired future renewable energy credits would not be completed until the first quarter of 2017.
The company previously expected the developer, Coronal Development, to complete the projects by year-end.
If Coronal misses its completion date, it is contractually obligated to pay Pacific the difference if it has to buy power at a higher cost on the energy market.
A dispute is raging in the state between drillers and landowners, who claim they are being cheated out of royalty payments for gas extracted from their land.
Although a 1979 law mandates a landowner royalty of at least 12.5% of the value of the gas, there are disputes over how the gas should be valued. Landowners contend they are entitled to 12.5% of what the gas sells for, while drillers say the proper calculation is market price, less post-production deductions for transportation and processing.
State lawmakers are scheduled to take up the issue Tuesday with a procedural vote on a bill that would prevent deductions from reducing landowner royalties to below the 12.5% state minimum.
Supreme Court Strikes Down Pro-Industry Drilling Law Provisions
The state Supreme Court last week struck down provisions of a 2012 law allowing state utility regulators to punish municipalities financially if they enact drilling rules stricter than state law.
The provisions generally had not been used, but the decision gives municipalities “breathing room” to enact tougher ordinances on the natural gas industry, said Jordan Yeager, an attorney for the Delaware Riverkeeper Network.
The high court also struck down two other provisions of the law. One pertained to a so-called “medical gag” rule; the other was characterized by one justice as illegal eminent domain for a private purpose.
State’s Pipeline Infrastructure not Keeping Pace with Gas Production
The state’s 60,000 miles of pipeline infrastructure is not keeping pace with natural gas production, industry leaders said in a conference call last week that addressed future gas pipeline expansion.
Some 25 to 30% of the state’s wells do not have full takeaway capacity, said Stephanie Catarino Wissman, executive director of Associated Petroleum Industries of Pennsylvania. The lack of pipeline infrastructure is hurting production from the Marcellus and Utica shales, Wissman said.
Pierre, state and company officials held a ribbon cutting ceremony last week for the state’s largest solar project, which has begun generating power under a testing period before it starts feeding the grid Oct. 7.
The $2 million, 1-MW facility is a joint venture between Pierre, Geronimo Energy and Missouri River Energy Services. It is located on about nine acres near the city’s airport. The companies chose Pierre because of easy access to a substation and available land that could not be used to grow crops.
With 4,280 panels, the facility only took two months to build, an MRES official said.
McAuliffe Rejects Calls To Kill Atlantic Coast Pipeline
Amid protests from residents and environmentalists, Gov. Terry McAuliffe said last week that he lacks the authority to cancel construction of Dominion Resources’ Atlantic Coast Pipeline — and wouldn’t do so even if he could.
“I as governor do not have the right to call down to the Department of Environmental Quality and say, ‘Well I don’t like this,’” McAuliffe said on a local radio station. “I cannot deny an air and water permit as governor. I don’t have the authority. It’s done by statute. If you don’t like the regs and they get approved, then you need to talk to the legislature to change the law.” But the governor also said he supports the project, arguing that it will create jobs and is a safer alternative to transporting gas by train.
McAuliffe’s remarks come as about 150 people attended a public hearing of the Buckingham County Planning Commission to voice to their opposition to the pipeline. Because of the large turnout, the commission extended the public comment period to Oct. 17. The Chesapeake Climate Action Network is also planning a three-day protest outside the Executive Mansion in Richmond.
The state’s big gas utilities are filing legal challenges to a recent Department of Ecology rule that requires about two dozen large industrial emitters of greenhouse gases to reduce their carbon emissions by an average of 1.7% annually.
The rule applies to the state’s five oil refineries, Puget Sound Energy gas facilities in Sumas, Longview and Goldendale, and other large emitters, including the Grays Harbor Energy Center in Elma.
“Washington’s natural gas utilities believe that reducing greenhouse gas emissions is a matter that needs addressing, but the [Clean Air Rule] is not the solution,” Avista said in a statement.
Mayors, Consumer Groups Protest FirstEnergy Plant Sale
More than a dozen groups, including city officials, energy efficiency organizations, natural gas companies and consumer advocates, have sent a letter to the Public Service Commission to protest FirstEnergy’s sale of the Pleasants power plant to one of its subsidiaries.
The groups say FirstEnergy is trying to save the money-losing coal plant by selling it to either Mon Power or Potomac Edison, which can get a guaranteed rate of return for the plant’s power. They told the PSC the utilities should bid for the lowest cost power, and that FE should have to prove selling the plant to one of the utilities is the most affordable option for consumers.
Fitch downgraded the state’s credit rating from AA+ to AA, citing the failing coal industry and a slump in profitability from natural gas.
The agency did note the growth in the service, transportation and warehousing industries, but they were not enough to buoy the state’s economy, which still relies heavily on coal. The state is also steadily losing its population to other states, Fitch said.
“We must work continually to diversify our economy through projects like the Hobet mine site redevelopment, while also maintaining a balanced, smart budget without irresponsible cuts to critical programs,” Gov. Earl Ray Tomblin said.
Legislative Committee Kills Wind Production Tax Increase
A state legislative committee voted down a proposed increase on the state’s wind energy production tax, the only such tax in the country.
The legislature has been seeking a way to close a multimillion-dollar budget shortfall, caused in part by a decline in revenue from the fossil fuel industries. But after hearing five hours of testimony from wind companies and local communities, the committee voted against moving forward a bill that would have raised the wind tax from $1/MWh to $3. Everyone who spoke at the hearing on the bill was against it.
Rep. Michael Madden, a committee co-chair, supported the bill, pointing to a new wind project that would have raised $40 million alone. The state is facing a gap of $200 million. “I don’t know what we’re going to do now,” Madden said.
In an industry where grid operators often engage in bickering and litigation over their borders, ERCOT and SPP have proven neighbors can also collaborate for the common good.
The grid operators’ in-house developers have worked together to produce version 2.0 of the Macomber Map, a visualization tool for control rooms. Projected on large overhead monitors, the map provides a geographical depiction of the system, including customizable views of power flows, constraints and other core system data that feed into the map and are then pieced together.
“As we collaborate on the software, we’re supporting each other,” said Mike Legatt, ERCOT’s principal “human factors engineer.” Legatt says the Macomber Map improves operators’ decision-making by increasing their situational awareness and simplifying the complexity wrought by integrating renewable resources, changes in market design and faster information flows.
“Our experience … is a great illustration of a new way of thinking, both about the relationships between technology and grid reliability and between independent grid operators like ERCOT and SPP,” said Cody Parker, SPP’s supervisor of operations support. “The adoption rate of users has been tremendous. It’s been clear that the … user-friendliness of the tool, the performance and responsiveness of the tool … those aspects have won over all the operators.”
Seeing the ‘Big Picture’
The system is named in honor of its creator, ERCOT’s Gary Macomber, a human factors engineer who died in August 2008, a few weeks before his first map became a production-level tool.
“Gary was really an incredible guy. He could see the big picture,” Legatt said. “This was the one [project] he was really excited about, because it’s pulling together disparate data from people who gather it. By doing all that work for the operators, it gives them more time and more mental bandwidth to be solving these problems.”
Legatt Source: ERCOT
“It’s opened up a whole new visualization framework without having to go through the physical process of drawing things pixel by pixel,” said SPP senior engineer Jeff Parker (no relation to Cody). “We’ve been able to use modern graphics-rendering capabilities built into it, instead of the old style of manually drawing everything.”
Legatt was behind the code for the map’s first version. However, he’s quick to say it’s the control room operators who developed the map.
“It’s all the users — operators, engineers and other groups within our organization — that have really defined how the tool grew and developed into what it is today,” he said.
In 2013, ERCOT released the code to the open source community for adoption by other users, such as governments, utilities and emergency responders who could benefit from improved situational awareness. The code has also been picked up by power-flow engineering students.
That led to version 2.0, which has an improved graphical user interface, among other upgrades.
Legatt credits SPP’s developers and operators for the new features. SPP staff tailored the tool to aggregate and analyze historical and real-time data from their energy management, markets, weather and other systems. The grid operators said SPP’s improvements enable operators to run what-if scenarios to monitor and mitigate congestion and outages.
“They’ve done some incredible work,” Legatt said of SPP. “They are showing things we were already showing, but in a better way. The graphical rendering is much nicer and much faster. It works better in remote-access situations … all thanks to Cody and his team.”
Human Factors Engineering
Cody Parker and his team became interested in Legatt’s work on human performance improvement through mutual industry contacts. Human factors engineering, also known as cognitive ergonomics or user-centered design, combines psychology and engineering.
Parker spent several months talking with Legatt, who has two master’s degrees and a doctorate in clinical health and neuropsychology. He recently defended his thesis in pursuit of a second doctorate from the University of Texas at Austin in energy systems engineering.
Once SPP’s Integrated Marketplace went live in 2014, Parker and his team were able to devote their full energy to adapting the map for their use.
Parker (l) and an unknown fellow SPP employee Source: SPP
“Working with Mike Legatt has been an absolute pleasure. It’s the key to our success and the ongoing coding,” Jeff Parker said. “He brings a whole new layer of ideas and questions … as we implement a requirement.”
After Legatt joined ERCOT in 2006, Macomber asked him to sit with ERCOT’s operators so he could understand their needs. “It became even more clear why we needed this tool,” Legatt said.
ERCOT began using the map’s first release in its training exercises in 2009, allowing its operators and those of market participants to visualize system restoration in black-start exercises and other scenarios.
Woody Rickerson, the ISO’s vice president of grid planning and operations, says he has seen performance continue to improve in training exercises. “That tells us those operators are even more prepared for success in real-life situations,” he said.
‘Eye-Opening’ Visit
Cody Parker visited ERCOT during one of the black-start exercises. Seeing the training was “very eye-opening,” he said.
Parker and his team took the code back to SPP and, after six months of development, integrated the tool with its other systems. The RTO has been using the map in its operations since March and recently began using it to train all of their operators. Parker’s team is now working on making the tool available to SPP’s external training department.
“We were able to take the users’ feedback and quickly apply it,” Parker said. “More often than not, that enhanced development was available for the [next] round of trainers. That was one of the huge advantages of going with the open-source solution.”
“The nice thing about using a product we have the source code for is we can go in and make things the way we need to make them work. Using a vendor’s tool, we just couldn’t go in and make any changes we wanted,” said SPP’s Tim Van Prooyen, a senior operations programmer and analyst.
One of the tool’s other advantages is that its updated rendering makes it easier to run on virtual machines — programs that emulate dedicated hardware.
“Before, you needed a physical machine on each person’s desk, but now you can [use] virtual systems without dedicated video graphics cards. Any user can pretty much use it on any machine, remote and on-site,” Parker said.
“The only thing we ask is if they find out ways to make it better … to let us know about it,” Legatt said. “One of the benefits of open sourcing the map and building these kinds of collaborations is that different parties need different things. So every enhancement they make that flows back to the open-source community benefits everybody else, moving us all to a better place.”
“This one project has opened the doors in multiple aspects,” Jeff Parker said. “It’s been much more of an exchange of ideas beyond the Macomber Map.”
Asked what version 3.0 might look like, Legatt promises it will be exciting. “The best thing is this collaboration with SPP. We have proven to ourselves this philosophy works.”
The Macomber Map’s source code and more information can be found here. Legatt said he and others can provide additional information and training support to help others customize the map to serve their own needs.
WILMINGTON, Del. — The coalition of municipal utilities and cooperatives seeking a review of PJM’s capacity construct decided last week to make revisions before approaching stakeholders for approval of its problem statement and issue charge.
American Municipal Power’s Ed Tatum said the coalition is incorporating feedback from other stakeholders. It plans to present a revised proposal at October’s Markets and Reliability Committee meeting.
Tatum conducted an informal poll of the MRC attendees and found about a dozen members willing to say the proposal was too broad. No stakeholders raised their hands when Tatum asked if they believed PJM’s capacity construct was immune to the policy changes of its member states.
Stakeholders have previously expressed concern that energy policy decisions made by states — from renewable energy production goals to utility reregulation — might disrupt PJM’s complex marketplace.
Delaware Municipal Electric Corp., Old Dominion Electric Cooperative, the PJM Public Power Coalition, the Public Power Association of New Jersey and retailer Direct Energy have signed on as cosponsors of AMP’s initiative, which was introduced at the August MRC meeting. (See Proposal to Revisit PJM Capacity Model Receives Tepid Response.)
Stakeholders largely applauded withdrawal of the proposal last week, saying it requested too much change too soon. “We haven’t even gotten through the transition for [Capacity Performance] yet where we have full CP,” said Calpine’s David “Scarp” Scarpignato. “It seems premature to be discussing a whole new concept.”
Susan Bruce, who represents the PJM Industrial Customer Coalition, expressed appreciation for the coalition’s willingness to consider other perspectives on the issue. “No one would call us a defender of PJM capacity markets, but at the same time, the idea of additional uncertainty and change … was something, from a business perspective, that was difficult for our clients to get our head around,” she said.
Exelon’s Jason Barker said his company is unlikely to support redesigning the entire capacity market, likening it to rewriting the U.S. Constitution rather than just individual laws. But he said it could be supportive of “something that’s a little more surgical.”
“Given the strong push by local, state and federal governments to recognize the environmental impacts of our industry, that seems like something that’s ripe for discussion,” he said. “That seems like an issue that has not been addressed” by PJM’s current system.
Continuing the medical analogy, Marji Philips of Direct Energy argued the issue should be addressed comprehensively rather than in pieces.
“I’m sympathetic to the fact that people thought this was overreaching, but the reality is we are amending CP by small cuts. We were suggesting that we just operate on the patient holistically instead of limb by limb,” she said. “I have to say, every one of us is guilty around here of claiming that we want regulatory certainty until a rule is bad for us, and then we want it changed right away, so unfortunately our reality is there is no regulatory certainty.”
FERC last week approved CAISO’s plan to implement a new market mechanism designed to improve the real-time integration of the increasing volume of variable renewable energy resources coming on to the ISO’s system (ER16-2023).
This red line in this graph represents CAISO’s projected net load profile in April 2020, after California meets its 33% RPS. Net load represents total load minus output from wind and solar resources and provides an indication of the ISO’s ramping needs in the face of high solar penetration.
The flexible ramping product will also be incorporated into the CAISO-run Western Energy Imbalance Market.
The product will enable the ISO to procure resources equipped to quickly respond to dispatch orders and ramp output up or down in response to swings in forecasted net load between five-minute real-time market intervals.
Net load is the ISO’s gross load forecast minus output from intermittent wind and solar resources. The new product will also allow the grid operator to procure additional ramping capability to account for uncertainty in its forecasts.
The mechanism is intended to help CAISO prevent power balance violations that can result from mismatches between generation and load, a growing risk as California moves toward fulfilling its mandate to generate 50% of its electricity from intermittent renewable resources by 2030.
The procurement of ramping capability will be bundled into the real-time energy market run, rather than being administered through a separate bidding process. Under the mechanism, load or supply resources that increase the need for ramping capability between real-time market intervals will be charged for the flexible ramping product, while resources that decrease the need will receive a payment.
“Settling ramping capability directly between load or supply resources that consume ramping capability and those that provide ramping capability will help manage the ramping need by incentivizing load-serving entities to have a portfolio of both dispatchable and non-dispatchable resources that can follow their load profile,” CAISO said in its proposal.
The ISO says the ramping product is readily dispatchable, distinguishing it from an ancillary services product for standby “unloaded” capacity withheld from the market.
The product replaces CAISO’s flexible ramping constraint, an interim measure implemented in 2011 to ensure upward ramping capability of dispatchable resources in the 15-minute real-time unit commitment process.
That measure enabled the ISO to reserve uncommitted ramping capability from dispatchable resources that were not designated to provide contingency or regulation reserves and whose upward ramping capability was not forecast to be needed to meet real-time loads.
The new product addresses the ISO’s need for shorter dispatch intervals and downward ramping capability.
Bidding Process Rejected
In its ruling, the commission rejected a request by the Western Power Trading Forum, the Electric Power Supply Association and the Independent Energy Producers Association to subject procurement of the flexible ramping product to a bidding process similar to that used for ancillary services.
“That the flexible ramping product may meet the definition of an ancillary service, or be similar to other ancillary services, such as spinning reserves or regulation, does not require that CAISO procure it in the same manner as those other products,” the commission wrote.
FERC also denied a request by the Six Cities municipal utilities — Anaheim, Azusa, Banning, Colton, Pasadena and Riverside — that it condition its approval of the product proposal on successful completion of market simulations. The commission said the ISO already stated that it would not roll out the product until it completed simulations and addressed market participants’ concerns.
The commission rejected as beyond the scope of the proceeding a request by the California Energy Storage Alliance to lower the ramping product’s -$150 bid floor.
On Sept. 28, CAISO petitioned the commission to delay the effective date for the product implementation by one month until Nov. 1. The ISO said that it didn’t learn of FERC’s decision until hours after a Sept. 26 call scheduled to confirm the roll-out to market participants. A decision on the petition is pending.
MISO transmission owners will be taking a pay cut, as FERC ordered their 12.38% return on equity reduced by more than 2 percentage points.
The Wednesday order (EL14-12-002) affirms an administrative law judge’s initial decision in December. The TOs will now receive a 10.32% ROE. With incentives, the rate is not to exceed 11.35%. The previous 12.38% rate had been untouched since 2002.
The decision affects more than 20 TOs, which FERC said must issue refunds, with interest, from Nov. 12, 2013, through Feb. 11, 2015.
The companies are ALLETE, Ameren, Cleco Power, Duke Energy, Entergy, Indianapolis Power & Light, ITC Holdings, MidAmerican Energy, Montana-Dakota Utilities, Northern Indiana Public Service Co., Northern States Power, Otter Tail Power, Southern Indiana Gas & Electric Co. and their affiliates. The order puts American Transmission Co. back on an equal footing with other MISO TOs; the company was operating at a 12.2% ROE.
Source: ITC Holdings
Minnesota officials have estimated the cut will save ratepayers in the 15-state MISO footprint $200 million a year.
The commission said the 10.32% rate “represents the midpoint of the upper half of the zone of reasonableness” of 7.23 to 11.35%.
Setting the rate nearer the “midpoint of the zone of reasonableness [at 9.29%] could impair investment in transmission” and put MISO Transmission Expansion Plan investments at risk, the commission said.
“There is record evidence that a decrease in ROE of that magnitude — a 309-basis-point reduction from 12.38% to 9.29% — could undermine the ability of MISO TOs to attract capital for new investment in electric transmission,” FERC said.
A 9.29% ROE would also have been lower than all of the state-authorized rates of integrated electric utilities.
Challenge Filed in 2013
MISO’s major industrial customers challenged the region’s transmission rate in 2013, requesting it be cut to 9.15%.
FERC arrived at the new rate using a discounted cash flow model that analyzed about 40 similar companies with the same range of credit as the MISO TOs over six months. The commission said the midpoint of the zone of reasonableness was adjusted upward because of “unusual capital market conditions” attributed to temporarily low interest rates, historically low bond yields and the Federal Reserve holding record high bond amounts during the study period.
FERC said a “mechanical application” of the discounted cash flow model would fail to meet capital attraction standards under the Hope and Bluefield fair return standard. The commission adopted the two-step discounted cash flow method for setting ROEs in 2014’s Opinion 531. (See FERC Splits over ROE.)
A witness for the TOs had presented a capital asset pricing analysis that produced an ROE range of 7.50 to 12.61%, with a midpoint value of 10.06%. FERC said the analysis, along with expected earnings and risk premium analyses supplied by the TOs, persuaded it that a higher midpoint on its own range — produced under the discounted cash flow analysis — was in order.
FERC also dismissed protests that it had not provided evidence to support its north-of-the-midpoint decision, saying it had “discretion to use its judgment in weighing factors specific to a given proceeding to determine where within the zone of reasonableness the final base ROE should be placed.”
The commission also declined transmission customers’ request to reduce the base rates of utilities with 55% equity by 20 basis points.
MISO and independent power producers asked FERC on Wednesday to dismiss a complaint by transmission customers seeking to overturn the results of the RTO’s 2016/17 Planning Resource Auction (PRA).
The Sept. 8 complaint by the Coalition of MISO Transmission Customers claims MISO misapplied its Tariff, causing the South-North transfer limit to bind sooner that it should have, driving up prices in MISO North (EL16-112).
Prices in Zone 1 cleared at $19.72/MW-day and Zones 2, 3, 4, 5, 6 and 7 each cleared at $72/MW-day after MISO limited capacity imports from MISO South to 876 MW. MISO South cleared at $2.99/MW-day. (See MISO’s 4th Capacity Auction Results in Disparity.)
On Wednesday, MISO responded to the complaint, saying it is a “several-month-late challenge … and fails to demonstrate any Tariff violation.” MISO said it calculated the constraint properly and that the coalition raised no objections when the results were shared with stakeholders nearly a month before the auction.
The Independent Market Monitor filed comments backing MISO, saying the customers failed “to identify a single provision of the Tariff that MISO failed to abide by when MISO calculated” the constraint.
The Electric Power Supply Association filed a protest saying the complaint should be dismissed because it is based solely on the 2016/17 PRA results. “The [coalition] has not demonstrated any violation or wrongdoing as required under FERC Rule 206 that would support its request to unwind the results of the 2016/17 PRA,” the group wrote.
Dynegy also called for FERC to reject the complaint, which it said “ignores express provisions of the Tariff and the settlement” between MISO and SPP over the transfer limit.
Illinois Attorney General Lisa Madigan filed comments supporting the complaint. Eight state regulatory bodies are among the more than 35 intervenors as of this week. The Organization of MISO States also filed to intervene.
Excess Capacity Trapped?
The complaint was filed by McNees Wallace & Nurick, which represents industrial customers. The coalition said it is an ad hoc association of large industrial customers that consume more than 8 billion kWh of electricity annually.
The customers claim Entergy’s territories in Zones 8, 9 and 10 had excess capacity, but MISO’s transfer limit caused it to become trapped in the South, leading to the higher prices in the Northern zones. They argue the limit should have been increased by at least 206 MW, which would have led to north prices clearing at just $20/MW-day.
The coalition asked FERC to reset Northern clearing prices to $20/MW-day and order MISO to issue refunds from June 1, the beginning of the planning year. The customers also asked that FERC conduct an audit of the Monitor’s approval of offers in the PRA, alleging that the Monitor did not rein in unreasonably high going-forward costs.
Currently, MISO subtracts firm reservations from the 2,500-MW South-North limit negotiated with SPP. The customers argue those firm reservations are never going to be used in full.
“The firm transmission service reservations of 1,624 MW that MISO deducted from the available system capacity usage of 2,500 MW do not reflect actual power transfers from the MISO South to MISO Midwest region. Rather, the deductions reflect firm service that MISO has agreed to provide NRG Energy Inc. in order to allow NRG capacity resources located in the MISO South region to qualify as a capacity resource in PJM,” the complaint said. “There is no evidence that NRG is, in fact, using this firm transmission reservation during the 2016/17 planning year to actually flow energy from MISO South to MISO Midwest in such a way that NRG’s full transmission reservation should be deducted from the 2,500 MW total.”
The complainants say MISO “overstates the impact of firm transmission reservations” and does not consider “the actual or reasonably likely use of the firm transmission reservation.” The customers said the transfer limit problem was recognized in the IMM’s 2015 State of the Market report.
In its own filing Wednesday, NRG said that while “the MISO Tariff should expressly address how internal transmission constraints should be modeled, there is no evidence that MISO violated its existing Tariff.” If the commission grants the coalition’s request for relief, NRG said, it should require MISO to calculate the sub-regional constraints by only deducting pseudo-ties from the 2,500-MW limit.
The coalition asked FERC to fast-track its complaint, saying it wants a decision in time to implement changes before next year’s PRA.
Changes Being Discussed
MISO is already considering adjusting the South-North transfer limit in planning for next year’s auction. A draft proposal on the 2017/18 sub-regional limit is on the agenda for the Oct. 5 Resource Adequacy Subcommittee meeting. (See MISO Proposes Study to Measure Benefits of New North-South Tx.)
In its response to FERC, MISO said the “complaint raises more problems than it alleges to solve.”
“It also requires the assumption that market participants will act against their own economic interest in scheduling transmission,” the RTO said.
NextEra Energy and Energy Future Holdings have assured Texas regulators they won’t be constrained in their review of the NextEra’s agreement to purchase Texas utility Oncor, which includes a $275 million termination fee.
During an update hearing Sept. 26 on EFH’s emergence from Chapter 11 bankruptcy (14-10979-CSS), Judge Christopher S. Sontchi said he had filed a joint letter from EFH and NextEra addressing the Public Utility Commission of Texas’ concerns.
PUCT Commissioner Ken Anderson said during a Sept. 22 open meeting that the termination fee “appears to be an effort to really tie the commission’s hands in the proceeding,” as it would allow NextEra to cancel the deal if the commission imposed “overly burdensome” conditions. Anderson also called the fee an “improper attempt to constrain the commission.” (See Texas PUC Expresses Doubts over NextEra-Oncor Deal.)
NextEra has proposed buying Oncor, EFH’s transmission business, for $18.7 billion.
According to the letter, “NextEra is not entitled to a termination fee under the merger agreement if NextEra Energy terminates the merger agreement because the commission either approves the merger agreement transaction with ‘burdensome conditions’ … or does not approve the merger agreement transaction.”
NextEra and EFH said the termination fee would be triggered only if EFH or Energy Future Intermediate Holding Co., Oncor’s direct parent, terminate the merger agreement. The companies wrote they “would like to make clear that, in any event, NextEra will not seek to collect any portion of the termination fee contemplated by the merger agreement in the event it terminates the agreement.”
Sontchi opened Monday’s hearing by quoting from the transcript of the PUC meeting.
“I believe [the] letter addresses the concerns raised by Commissioner Anderson,” Sontchi said. He said any possible triggering of the termination fee is “an issue for the bankruptcy court, and not for the PUCT and ratepayers.”
The PUCT’s approval is just one of several favorable regulatory rulings NextEra and EFH must secure before closing the deal.
FERC rejected for a second time Arizona Public Service’s proposed rules over how external resources can use dynamic scheduling to participate in the Western Energy Imbalance Market (EIM).
The commission ruled that APS’ tariff changes failed to comply with an April 29 directive to “clarify that dynamically scheduled external resources are not required to enter into commercial contracts with APS in order to participate in the EIM” (ER16-938).
FERC’s Sept. 26 order affirmed that APS could require dynamically scheduled external resources to have the technical capability to provide load-following and regulation services, but it said APS could not condition eligibility on their provision of the services.
“Consistent with the April 29 order, we affirm that APS may not condition a dynamically scheduled external resource’s participation in the EIM on its contracting to provide load-following or regulation service to APS,” the commission wrote.
Arizona Public Service’s Hassayampa-Gila 500 kV line serves the utility’s Phoenix load center. Photo Source: AECOM
EIM members PacifiCorp and NV Energy currently restrict external EIM participation to only those resources pseudo-tied into their respective balancing areas. While APS will allow EIM transfers via pseudo-ties, the utility elected to further extend market participation to those external resources equipped to dynamically schedule into its transmission network.
But APS required that dynamically scheduled resources meet the tariff-defined qualifications of a Balancing Authority Area Resource (BAAR).
Under the EIM’s rules, a BAAR designation denotes a resource’s eligibility to contribute to an EIM participant’s “available balancing capacity” — the verifiable operating reserves a market participant carries to ensure that it isn’t leaning on the EIM to meet its capacity requirements.
APS’ tariff proposal included requirements that a BAAR resource be unit-specific rather than an unspecified system resource and be able to provide regulation and load-following services to help the utility to meet its resource adequacy criteria.
The proposal also required that a BAAR either be owned by APS or under contract with the utility for energy, ancillary services or capacity.
In its April order, the commission objected to that last provision and directed the utility to clarify that external resources do not have to qualify as a BAAR in order to transact with the EIM.
Instead of inserting a new provision covering dynamically scheduled resources, APS’ compliance filing redefined BAARs to exclude the ownership and contracting requirements. The utility expressed concern that removing the BAAR provision could enable resources to circumvent operational and technical specifications applicable to all resources participating in the EIM — specifications already approved by FERC. APS also contended that, by revising the definition to eliminate the commercial relationship requirement, it had complied with FERC’s directive.
The commission disagreed, saying that “APS has failed to comply with the directive to remove the requirement that an external resource qualify as a BAAR to be eligible to participate via dynamic scheduling.”
The BAAR qualification is “commercial in nature,” given that APS’ tariff still required any resource designated as such to provide load-following and regulation service, the commission found.
Market participants’ transactions in the EIM are expected to be voluntary and not subject to such obligations, FERC said. While an external resource participating in the EIM can enter a contract to provide ancillary services to APS, it cannot be required to do so, the commission said.
The commission ordered APS to restore the original commercial language to the BAAR qualification in order to ensure that APS and CAISO, the EIM’s operator, can identify those resources that contribute to the utility’s EIM capacity requirement.
“In the context of the available balancing capacity mechanism, it is crucial that APS either own or have a contractual right to call upon the capacity for regulation or load-following services from a designated resource,” the commission wrote.
Other elements of the ruling include:
FERC affirmed APS’s requirement that external resources participating in the EIM via dynamic scheduling be capable of responding on a unit-specific basis. “As APS notes, requiring that resources be unit-specific, will ensure that APS can distinguish an external resource’s dynamic schedule from an intertie bid,” FERC wrote.
The commission denied a rehearing request by the Southwest Public Power Agency (SPPA) over its approval of APS’s proposal to adopt EIM pricing of transmission losses without giving transmission customers the option of self-supplying losses within the same hour. The commission said FERC precedent does not “preclude the use of a financial settlement mechanism to the exclusion of in-kind replacement of losses.”
The commission directed APS to submit a compliance filing providing more details about the timing and duration of its evaluation of operating reserve obligation payments and credits from CAISO. SPPA contended that APS has not committed to ensuring that customers will share in the benefits of reduced reserve costs resulting from EIM participation.
Missouri, Maine and Michigan were the most-improved states, according to the study. The study identified Louisiana, Kansas, South Dakota, Wyoming and North Dakota as the states most in need of improvement.
Arizona Public Service and the Salt River Project say that customers who have installed rooftop solar panels on their homes are increasingly burdening those who haven’t.
The Irvine Ranch Water District is installing a 7-MW, 34-MWh energy storage system using Tesla batteries in what is billed as the largest network of energy storage systems at a public water agency in the U.S.
Pacific Gas and Electric last week filed a response to public comments submitted to the Public Utilities Commission on its plan to retire its Diablo Canyon nuclear plant in 2025.
Construction of a proposed NRG Energy power plant in Oxnard may be delayed after the company made some changes to its design, the state Energy Commission said at a public hearing last week.
The Commerce Commission voted unanimously to accept Ameren Illinois’ plan to expand the installation of smart meters to its entire service territory.
An over-budget transmission project, coupled with increased charges from dam construction, could double rates for Manitoba Hydro customers, according to a former Public Utilities Board member.
The Montana Environmental Information Center and Vote Solar filed a complaint with FERC claiming the Public Service Commission violated federal regulations when it suspended payments for energy projects while it reviews standard rates for small solar energy developers.
State regulators and environmentalists are clashing over reports that say new coal ash landfills at Duke Energy’s Sutton Plant in Wilmington and Dan River plant in Eden won’t unfairly affect anyone based on age, race, income or language.
Pacific Power announced last week that four solar power projects in central and southern Oregon from which it acquired future renewable energy credits would not be completed until the first quarter of 2017.
The state’s 60,000 miles of pipeline infrastructure is not keeping pace with natural gas production, industry leaders said in a conference call last week that addressed future gas pipeline expansion.
Pierre, state and company officials held a ribbon cutting ceremony last week for the state’s largest solar project, which has begun generating power under a testing period before it starts feeding the grid Oct. 7.
Amid protests from residents and environmentalists, Gov. Terry McAuliffe said last week that he lacks the authority to cancel construction of Dominion Resources’ Atlantic Coast Pipeline — and wouldn’t do so even if he could.
More than a dozen groups, including city officials, energy efficiency organizations, natural gas companies and consumer advocates, have sent a letter to the Public Service Commission to protest FirstEnergy’s sale of the Pleasants power plant to one of its subsidiaries.
itch downgraded the state’s credit rating from AA+ to AA, citing the failing coal industry and a slump in profitability from natural gas.
