CARMEL, Ind. — MISO is testing the waters for creating a multiday energy market that would keep generators with long start-up times switched on for more than one day.
The effort has strong backing from stakeholders, who last year assigned the introduction of multiday financial commitments a “high priority” in the RTO’s Market Roadmap. (See MISO Projects Reordered Following Stakeholder Frustration.)
MISO says the change will result in more cost-efficient unit cycling and more diversity in the selection of resources called up for commitment. Market participants have said that relying on the routine cycling of baseload units can lead to inefficient unit commitment and higher maintenance and capital costs when a slow-moving unit is repeatedly switched on and off to conform to a next-day schedule.
RTO staff will begin analyzing historical market data in order to assess the costs and benefits of committing units over multiple days, MISO Markets System Analyst Chuck Hansen said at a May 11 Market Subcommittee meeting. The existing day-ahead market is not designed to accommodate units with long lead times or high start-up costs, he said.
“For units with a long lead time, the day-ahead market is going to think that it’s not profitable to start that unit,” he said, adding that the day-ahead market does not typically commit units to serve reliability needs.
But MISO could stretch its market model to notify units days ahead of time when they will be needed.
Still, a multiday market raises the question of who pays for the risk of overcommitting resources. Hansen said that risk could either be assigned to market participants, or MISO could take on the risk with the creation of multiday revenue sufficiency guarantees, which could result in increased uplift payments. Stakeholders could even agree to eliminate the day-ahead market in favor of a multiday market, although it would be a huge undertaking, he said.
Wind units — forecasted only a day out — and forced outages could complicate how slow-response units are scheduled. Hansen also told stakeholders that the “potential to improve unit commitments may be limited” compared to self-scheduling. Resources with high production costs will almost never be committed, even in a multiday commitment market, Hansen said. On the flip side, resources with low production costs can self-commit and remain running.
A multiday market could be useful for even faster-ramping gas-fired units, which must complete their weekend gas reservations on Fridays, Northern Indiana Public Service Co.’s Bill SeDoris said.
MISO market engineer Shu Xu said the RTO would not include the elimination of the day-ahead market in its cost-benefit analysis because the scenario is impossible to test with current software.
That comment prompted DTE Energy’s Nick Griffin to ask if MISO’s impending market system overhaul would allow a multiday market to completely replace a day-ahead market. Dhiman Chatterjee, MISO’s senior manager of market analysis, responded that, given the target deadline for completing a cost-benefit analysis, the RTO could not wait on the development of an entirely new market software platform just to test for such a far-fetched scenario.
MISO hopes to complete its analysis late this year and produce a conceptual design for a new multiday financial commitment market during the first half of 2018.
ERCOT last month set a new record for April peak demand, registering a high of 53,420 MW during the hour ending 5 p.m. on April 28, easily exceeding forecasted demand of 51,622 MW.
That marked a 4.88% increase from the high for the same month last year, when the Texas grid operator recorded a peak of 50,932 MW.
Panda Power’s 758-MW combined cycle power plant in Temple, Texas. | Panda Power Funds
ERCOT’s previous high for the month occurred April 18, 2006, when unseasonably high temperatures led to a peak of 51,800 MW.
The ISO generated more than 26 million MWh of electricity in April, bettering the forecast of 25,872,676 MWh. For the year, it has produced 102.4 million MWh, up from 100.5 million MWh through April 2016.
Coal last month surpassed natural gas as ERCOT’s primary fuel source for the first time since January, accounting for 33.57% of the ISO’s energy production. Gas accounted for 33.31% of energy produced and wind another 24.88%. Nuclear dropped to 7.08% of energy production, down from its previous 2017 low of 12.67% in March.
INDIANAPOLIS — Coming off a bumpy 2016, Indianapolis’ first-in-the-nation electric car-sharing service is looking to resume its expansion with the construction of new charging stations and a campaign to attract more members.
And the French company backing the BlueIndy program hopes to transplant the model to California, which is aggressively pursuing the adoption of electric vehicles as part of its policies to reduce greenhouse gas emissions.
Launched by the Bolloré Group in September 2015, BlueIndy boasts about 300 cars and 85 five-port charging stations around the Indiana capital. The company has planned for an additional 200 cars and 115 stations, but events last year halted expansion.
“We haven’t changed the goal, but the construction slowed down a lot in 2016,” BlueIndy President Hervé Muller said in an interview. “We had to deal with some political issues and had to sign a contract with the city.”
BlueIndy put a hold on construction during most the year while negotiating an agreement with the Indianapolis City-County Council, which contended that the process for placing stations lacked transparency. Business owners also complained the stations were taking up parking spaces near their storefronts.
The company and the council eventually settled on a franchise agreement last fall that allows the city to possibly relocate up to seven stations and requires the company to pay the city $45,000 per year to compensate for lost parking meters. Business owners must show that they have suffered financially to get a charging station moved.
“That was unfortunate and it took a lot of tension and most of 2016 to negotiate the agreement,” Muller said. “We think that phase is behind us, learning the political environment. That page has turned.”
Rideshares in Sync with Public Transit
BlueIndy has yet to uproot any charging stations, although a recently voter-approved rapid transit bus route might require some relocations. Still, Muller is not concerned that buses will infringe on his company’s growth.
“The two are not competing,” he said. “If you need to go somewhere, and you don’t have a car, what are your options? On some days instead of using the bus, you might use the cars. We think it’s all complementary. It’s to give options to people who don’t own a car or don’t want to own a car.”
Muller said Bolloré’s AutoLib’ sharing service happily coexists with the expansive public transit in Paris, which he considers the company’s showcase city.
“There’s no debate there whether we are taking a rider from public transit,” he said. Bolloré has similar rideshare services in Lyon and Bordeaux in France; London; and Turin, Italy. The company will soon expand to Singapore.
Unlikely Host
The company is currently building five new charging stations in Indianapolis and awaiting word on a backlog of notices submitted to the city for review of prospective locations. Each station costs anywhere from $50,000 to $100,000.
Bolloré has converted its Midwestern host into an unlikely early adopter of EV technology. The company’s 400-plus public chargers give Indianapolis the distinction of having the largest network of public charging stations of any U.S. city. While the number of private charging stations in Los Angeles might currently outstrip those in the Indiana city, Muller noted that BlueIndy charging stations can be used by anyone.
Navigating the American political landscape for construction approval is not unlike working with government officials in France, Muller said.
“Our goal is to work well with local political power. That’s why we’re selective about the cities we go to,” he said. “It is a transformation of the city, and we do believe that electric vehicle sharing must happen in the public right of way.”
Bolloré has a 15-year contract with Indianapolis and anticipates investing a total of $41 million in BlueIndy, with the city funding $6 million and Indianapolis Power and Light contributing about $3 million. The company has hired about 40 full-time and part-time staff in Indianapolis to run the program and has contracted with local construction unions to erect charging stations.
Residents can sign up for membership at a charging station kiosk or the BlueIndy website, and reserve cars or charging spots via the website or an app. Members are charged according to a metered payment structure based on the first 20 minutes of use and a per-minute charge thereafter. Membership packages, which come with a monthly fee, reduce the per-minute charge by up to half. A daily rental, requiring no commitment, costs $8 for the first 20 minutes, then 40 cents/minute. With a one-year membership (about $120), the charge is $4 for the first 20 minutes and 20 cents/minute afterward.
BlueIndy is now focused on expanding its membership, currently 1,500 active members that take about 1,000 rides per week.
“That is really the measure of the service — how often the cars are used,” Muller said.
While the company doesn’t maintain detailed demographics on its current users, it does collect information through member surveys, which Muller said shows “a large contingent of young users, millennials and students,” as well as retired people and families that want to become a one-car family. The company last year also rolled out targeted discounts to encourage college students to join.
Muller estimates that BlueIndy’s profitability is still a few years out: “The nature of our business is a big infrastructure investment. We know that we’re going to spend millions and millions of dollars. We generally anticipate that it takes five to seven years to break even and after that we can recoup our investment.”
Bolloré Goes West
Having gained a foothold in the U.S., Bolloré is now eyeing a West Coast expansion with a BlueLA pilot program underway that will consist of 100 vehicles and 200 charging ports by the end of spring.
“Los Angeles is a fantastic city for our service,” Muller said. “We had always envisioned to employ our service in California. It’s starting as a pilot, but there’s a long-term vision to deploy a service similar to what we have in Paris or Singapore.”
The California Air Resources Board granted Los Angeles $1.6 million for the pilot, but Muller said Bolloré expects a similar 80-20 funding split like that in Indianapolis, with the company paying the lion’s share for construction and cars, and the city and local utilities picking up the rest.
Los Angeles Mayor Eric Garcetti said the stations will target low-income areas where residents are less likely to own cars. “We are so proud that we can now launch the nation’s first pilot program for electric vehicle sharing in disadvantaged communities. That is real progress,” Garcetti said.
Bolloré is not currently considering any other U.S. cities for expansion.
“We make a big investment in the charging infrastructure, so we make a careful decision,” Muller explained.
Different Locations, Same Cars
The EVs used for the service — Bolloré’s Bluecars — are nearly identical worldwide. The two-door, four-seater hatchback was developed with Italian automotive design firm Pininfarina and is manufactured in Italy. The cars have a top speed of 81 mph and an on-board computer for navigation.
While the Bluecars’ 30-kWh lithium metal polymer batteries can last for a 150-mile trip on a single charge, Muller said the total useful life of the battery is still unknown because the technology is so new. The batteries, which are produced in Bolloré’s factories, passed the five-year mark in 2016 in France with heavy use, and the company has yet to replace any of the recyclable batteries.
“We think it should outlast most batteries on the market. There is no known end of life for the batteries right now. We can say that they are exceeding our expectations,” Muller said.
A new CAISO initiative could allow power producers a way to temporarily suspend the operation of an unprofitable generating plant — and possibly provide compensation to plants denied permission to do so.
That would crack the door for the ISO to issue a type of capacity payment to some financially struggling generators not needed to maintain system reliability, even if it falls far short of establishing a capacity market.
The Temporary Suspension of Resource Operations initiative will explore under what circumstances the ISO might permit a resource owner to temporarily pull a money-losing generator out of the market short of the “mothball” and retirement procedures already spelled out in the ISO’s Business Practice Manual.
“The initiative will assess how potentially allowing this type of resource status change would interact with other requirements of the CAISO Tariff, contracts, and with grid and market operations,” the ISO said in an issue paper describing the scope of the effort.
CAISO said it was seeking to address the issue in response to stakeholder comments filed in a 2016 FERC proceeding over the ISO’s refusal to approve outage requests for three of four units at the 965-MW La Paloma combined cycle plant 140 miles north of Los Angeles (EL16-88).
Completed in 2003, La Paloma — like other gas-fired plants in California — has in recent years struggled to compete in the wholesale market because of depressed prices, largely driven by lower-priced renewable resources. The owners estimated that the plant would lose $39 million annually under continuous operation and asked that CAISO allow them to shut down the three units from July to November 2016.
The ISO rejected the plant owners’ requests because they were made for economic — and not physical — reasons. It also rebuffed an additional request to compensate the units by designating them as reliability-must-run resources, contending that they were not needed for reliability purposes. At that time, 42 MW of the plant’s Unit 2 were under an RMR agreement.
Last December, two months after FERC refused to overturn the ISO’s decision, La Paloma filed for bankruptcy, citing $524 million in debt and an “inhospitable regulatory environment.”
CAISO’s initiative stems from stakeholder concerns raised during a 2016 FERC proceeding related to the La Paloma generating plant, which filed for bankruptcy late last year after being refused permission to suspend its operations in the ISO market. | Kern County, California Public Health Services Department
While market participants generally agreed with CAISO’s decision, some suggested that FERC direct the ISO to amend its Tariff to address revenue shortfalls for conventional generators. FERC rejected the request.
The new initiative seeks to address at least some of those stakeholder concerns. In its filings with FERC, CAISO acknowledged the importance of keeping conventional generation available to help integrate the growing volume of renewables on its system and noted that it was actively pursuing market changes to compensate generators for their needed characteristics.
The ISO seeks to keep the scope narrow, avoiding a discussion of using the current outage management system — which is intended for maintenance outages — for economic requests.
“The distinction here is that this initiative will look at the conditions under which the CAISO may allow a participating generator to temporarily suspend the operation of its generating unit,” the ISO said in its paper. “The solution will likely involve a process and a new method for requesting and then reporting a temporary suspension of operations.”
Perhaps most significantly, the ISO wants stakeholders to consider the need for a mechanism to compensate generators not needed for resource adequacy but denied permission to suspend operations, including a potential cost allocation scheme.
The initiative will also explore maximum and minimum time limits for temporary suspensions, timelines for requesting suspension and whether suspended resources should maintain a level of readiness to return to the ISO market if it’s needed.
The ISO additionally expects to consider whether a generator can switch operation from one balancing authority area to a neighboring one for an extended period of time and how that would affect resource adequacy accounting.
Under current rules, owners that plan to mothball a generator must provide CAISO 60 days’ notice before shutting down and submit a “long-range” outage request. To maintain its repowering rights and deliverability status, the plant must provide a repowering plan within one year of closing.
CAISO will kick off the initiative with a May 19 stakeholder call.
Maryland regulators on Thursday approved two offshore wind projects totaling 368 MW, setting in motion what the state called the nation’s “first large-scale” offshore wind deployment.
The Public Service Commission awarded offshore renewable energy credits (ORECs) to US Wind and Deepwater Wind’s Skipjack Offshore Energy.
PSC Chairman W. Kevin Hughes said the approval “brings to fruition the General Assembly’s efforts to establish Maryland as a regional hub for this burgeoning industry.”
Maryland Offshore Wind Lease Area | BOEM
The PSC awarded the credits at a levelized price of $131.93/MWh for 20 years, beginning when the plants start generating.
US Wind’s 62-turbine, 248-MW project, 12 to 15 nautical miles offshore, has an estimated cost of $1.375 billion and is expected to begin operations in January 2020. It will connect to the grid at the Indian River Substation in Delaware.
Skipjack’s 15-turbine, 120-MW project, 17 to 21 miles off the coast, is estimated at $720 million and has a target in-service date of November 2022. It will connect to the grid at a substation in Ocean City, Md.
Conditions
The PSC’s order included more than two dozen conditions, including requirements that the developers create almost 5,000 direct jobs during the development, construction and operating phases of the projects.
The companies will be required to use port facilities in the Baltimore region and Ocean City for construction, operations and maintenance, fund almost $40 million in upgrades at the Tradepoint Atlantic (formerly Sparrows Point) shipyard in Baltimore County and invest at least $76 million in a steel fabrication plant in the state (Case No. 9431).
To address concerns about the ability to see the turbines from the shore, the order also requires US Wind to locate its project as far to the east of the designated wind energy area as practical. “Each developer also must take advantage of the best commercially available technology to lessen views of the wind turbines by beach-goers and residents, both during the day and at night,” Commissioner Anthony O’Donnell said.
The two companies must notify the PSC by May 25 whether they accept the conditions. The projects also are subject to the federal government’s approval of site assessment, construction and operations plans.
“As we review the details of the commission’s order, we thank the Public Service Commission for the trust that they have placed in Deepwater Wind,” CEO Jeff Grybowski said in a statement. “We look forward to continuing our dialogue with the Ocean City community about the Skipjack Wind Farm. Our goal is to build a project that the entire community is proud of.”
Deepwater Wind operates the first offshore wind project in the U.S., the 30-MW Block Island project off Rhode Island that began operations in December. (See Offshore Wind Industry Looks for Next Gust of Support.)
US Wind, a subsidiary of Italy’s Toto Holdings, thanked the PSC for the decision in a statement, saying “Maryland is now the undisputed national leader for offshore wind.”
| US Wind
“This marks the real start toward an extensive offshore wind industry that will one day soon stretch from Cape Cod, Mass., to Cape Hatteras, N.C., and provide as much as a third of the East Coast’s electricity,” the Chesapeake Climate Action Network said in a statement.
Cost to Ratepayers
An analysis conducted for the PSC estimated the ORECs will cost residential customers less than $1.40/month and boost rates for commercial and industrial customers by less than 1.4% — below the limit set by the legislature in the Maryland Offshore Wind Energy Act of 2013. The law allows offshore wind to comprise up to 2.5% of total retail electricity sales.
The projects are part of the state’s plan to reduce carbon emissions 40% by 2030 and will allow electric suppliers to replace some renewable energy credits produced in other states. Maryland’s renewable portfolio standard requires production of 25% of electricity from renewables by 2020.
CARMEL, Ind. — Customers of the Southwestern Power Administration (SWPA) asked MISO on Wednesday to change how it accredits their hydropower allocations from the federal power marketing administration, saying current rules are shortchanging them and denying the RTO full use of the resources’ seasonal peaking capacity.
“We didn’t come today with a fix. … We’re going to hope that the people in the room come up with a solution and a fix in future meetings,” Rick Henley, of Jonesboro City Water and Light in northeast Arkansas, told stakeholders at a May 10 Resource Adequacy Subcommittee meeting. Appearing on behalf of SWPA customers with Aiden Smith, the agency’s vice president of transmission strategy, Henley offered a problem statement outlining their concerns.
Move from SPP to MISO
SWPA markets about 2,000 MW of power produced by 24 U.S. Army Corps of Engineers hydropower projects, most of them located in the SPP footprint.
When Entergy joined MISO in 2013, it added 27 SWPA customers to the RTO’s footprint in addition to one existing customer. “As a result, the vast majority of SWPA’s federal hydropower customers were not present in MISO’s stakeholder processes when the rules concerning resource adequacy were crafted,” the problem statement said.
The problem, Henley said, is that MISO’s resource adequacy rules treat the hydro assets as baseload power when they were designed to provide peaking power. He said MISO could reap reliability benefits in the summer and winter if it modified its requirements for hydro assets.
MISO’s Business Practice Manuals require the Use-Limited Resource type to be available for the four peak hours of the day (1,460 hours/year). But because SWPA’s contracts with Jonesboro and other “preference customers” typically only guarantee power for 1,200 hours/year, MISO revised its rules to give the SWPA customers a reduced capacity credit of 82% of their federal allocations to spread the guaranteed amount of firm energy across 1,460 hours.
Intended as Peaking Power
“While the federal preference customers are very grateful for this compromise, MISO, its footprint and the customers could be better served by federal hydropower if it was used as intended as peaking power,” the problem statement says.
It noted that SWPA hydropower has 236 MW of import capability into MISO. It said one unnamed preference customer with a 100-MW allotment is not importing into the RTO because of the current rules but would do so if the problem were resolved.
“We have a 1,200-hour product that does not conform with MISO’s 1,460-hour resource adequacy rules,” Henley said. “We’re scheduling now as a baseload resource, and we think it reduces the ability of the federal hydropower when it’s most needed and valuable in the MISO footprint. If we can bring more resources to the table, you [would] think that would bring down prices for everyone.”
Jonesboro City Water and Light, which has a 303-MW peak demand for 36,000 customers, has an 80-MW hydropower allocation from SWPA. “It’s a pretty big deal for us,” Henley said of the hydropower share. “We think there’s a better way to utilize this resource within MISO constraints.”
David Sapper of Customized Energy Solutions said stakeholders have long considered asking MISO to revise its resource adequacy rules, saying it’s difficult for any fuel type to meet the availability requirements.
RASC liaison Shawn McFarlane said MISO can examine the issue with stakeholders, but he said the RTO would not commit to a timeline. He said it could work to compile statistics on hydropower use for stakeholders.
“Obviously, anything we apply has to work generally; we cannot create one-offs,” McFarlane said.
RASC Chair Chris Plante said stakeholder process dictates that the issue is first sent to the Steering Committee, which would decide which committee works on it. Steering Committee Chair Tia Elliott said her committee would most likely move the issue to the RASC at the May 24 meeting.
Texas regulators on Wednesday agreed to reconsider its recent rejection of a proposed acquisition of Oncor by Florida-based NextEra Energy, which sought a review of the decision.
The state’s Public Utility Commission will rehear the case (Docket 46238) during its May 18 open meeting, the first without longtime Chairman Donna Nelson, who is retiring May 15. No replacement has yet been named to the three-person panel. (See Texas PUC Chair Nelson Stepping Down.)
The PUC last month unanimously rejected NextEra’s $18.7 billion bid for the Texas utility, saying the risks outweighed the promised benefits. (See Texas Commission Denies NextEra’s Bid for Oncor.)
In a filing made earlier this week, NextEra said the commission went beyond the scope of its powers when it found the acquisition not to be in the public interest, calling the PUC’s order “unprecedented.”
“The order represents an expansion of power that exceeds the limits set by the Legislature and the bounds of the commission’s own precedent,” NextEra said, listing 14 points of error ranging from “the exercise of authority not granted by the Legislature to reliance on facts not in evidence.”
The company said the order also ignores “Moody’s determination that NextEra Energy’s acquisition … will unequivocally benefit Oncor,” and that it fails “to give any consideration to the benefits and protections” of the 73 regulatory commitments the company made to the PUC.
NextEra requested the commission give it as much time as allowed by law to “encourage possible settlement discussions.”
At stake is a $275 million termination fee that NextEra would be liable for should the deal fail for certain reasons.
The PUC has until June 7 to act on NextEra’s request.
Oncor’s future is central to parent company Energy Future Holdings’ bid to exit Chapter 11 bankruptcy proceedings, which have now dragged on for three years. The PUC rejected Hunt Consolidated’s bid for Oncor last year.
Duke Energy is asking North Carolina officials to revisit state rules around renewables and provide the utility with greater control over what generation resources it must use, company executives said during a first-quarter earnings call Tuesday.
The largest utility in the U.S. posted a first-quarter profit of $716 million ($1.02/share) compared with $694 million ($1.01/share) a year ago. The increase was helped in part by last year’s acquisition of Piedmont Natural Gas.
Adjusted earnings per share were $1.04, down from $1.13 in the first quarter of 2016 and just missing analyst expectations. Executives attributed the decline to mild weather — along with the sale of Duke’s international energy business in December — and announced plans to cut about $100 million in expenses.
Turbine blades prepared for installation at Duke’s Frontier Windpower Project in Oklahoma | Duke Energy
Duke’s electric business reported income of $635 million, down $9 million year over year, while earnings at its commercial renewable energy arm, which sells solar and wind power to other utilities and corporate customers, fell by $1 million to $25 million.
The company is pursuing two separate actions through North Carolina’s government to exert increased control over the generation it must use to serve customers.
First, Duke has asked the North Carolina Utilities Commission to reduce what the utility must pay qualified facilities under the Public Utility Regulatory Policies Act, which requires electric utilities to pay such facilities the avoided costs of not building traditional power plants. In its filing, Duke said that rate has dropped to $35/MWh from currently recognized rates of $55 to $85.
Company CEO Lynn Good said that action went to hearing in mid-April.
Duke is also lobbying members of the state legislature to develop an annual competitive process that sets out a determined volume of renewable resources.
“What’s being proposed is an opportunity to move this development of renewables and solar in the state into a more sustainable model,” Good said. “A competitive process would impact [the] price to customers and [we] believe that better planning and better pricing would create a more sustainable market. … We believe it’s costing customers about $1 billion more than a market price would cost them over a 12-year period.”
The explanation came as Good and other company executives described plans to shift renewable investment toward regulated jurisdictions rather than commercial. Duke has $2.5 billion slated in its five-year plan for such investments, about $1.5 billion for regulated regions and $1 billion in commercial.
Duke’s solar facility at Camp Lejeune in North Carolina
“Returns are tight, [and] the tax position is uncertain for us at least over the next couple of years,” Good said. “We feel like we have a really strong portfolio of 3,000 MW [of] wind and solar, backed by a long-term contract.”
Good noted that the “majority” of Duke’s revenue in renewables comes from wind production tax credits as investment tax credits from solar construction dropped by a penny year over year.
Duke Energy line worker | Duke Energy
She highlighted a $25 billion, 10-year plan for grid modernization, which includes investments to automatically reroute power and accelerate grid restoration when necessary. She also described plans to spend $4.9 billion to bury underground “select sections of poorly performing overhead lines, many located in hard-to-access areas” in the Carolinas.
“We found that our heaviest concentration of densely vegetated lands that cause outages are really preponderantly in the Carolinas,” said Lee Mazzocchi, of the company’s Grid Solutions group.
While Good touted a 2016 safety achievement award for Duke’s Midwestern local distribution companies, she omitted any discussion of environmental safety issues at coal ash piles that the company estimates will cost $5 billion to address. Only one question from analysts touched on the subject, and that was simply to ask if the company’s plans were changing in light of potential changes on the federal level.
American Electric Power and Dynegy on Tuesday completed the transfer of their stakes in a pair of Ohio coal-fired plants that the two companies own in common.
The transfer is part of AEP’s strategic review of its merchant assets.
AEP sold its 330-MW (25.4%) share of the Zimmer plant and will assume Dynegy’s 312-MW (40%) interest in the Conesville plant. As part of the deal, AEP returned a $58 million letter of credit to Dynegy.
AEP’s Conesville Plant | Ohio Citizen Action
Columbus, Ohio-based AEP now owns 92% of Conesville’s four units, with Dayton Power & Light holding the remaining 129 MW of Unit 4.
AEP’s other competitive assets in Ohio include a 595-MW unit of the Cardinal plant near Brilliant, Ohio; 603 MW of the Stuart plant near Aberdeen, Ohio; and a 48-MW hydro plant near Racine, Ohio.
The Stuart plant, of which AEP owns a 26% share, is expected to be retired by June 2018.
AEP CEO Nick Akins made reference to the swap during the company’s April 27 earnings call with financial analysts when he said, “We continue to explore our strategic alternatives with [Conesville and Cardinal] and, in the case of Cardinal, seeking ways to enable a more modern and efficient relationship … as we explore our strategic alternatives in parallel.”
AEP created its competitive generation company, AEP Generation Resources, in early 2014 after separating its distribution and transmission operations in Ohio from its AEP Ohio-owned generation assets.
MISO’s summer planning reserve margins will remain firmly above requirements even after it shaved nearly half a percentage point from an initial assessment for the season.
Reserve margins could range anywhere from 14.1 to 19.7% throughout the summer, and MISO sees a high probability (79.3%) for calling up load-modifying resources and a much lower one (12%) for exhausting its 10.2 GW of LMRs and dipping into operating reserves. The chance of load shedding stands at 5%.
| MISO
Based on forecasts for above-normal temperatures in its footprint this summer, the RTO expects peak demand to hit 125.1 GW, with 148.5 GW of available capacity on hand to meet it. Summer demand peaked at 120.7 GW last year.
“We are expecting to have sufficient resources in the footprint,” Todd Ramey, MISO vice president of system operations, said during an annual summer readiness workshop on May 8.
While forecasts for declining demand are driving up the base reserve margin, the increased Midwest-South regional transfer limit is providing extra wiggle room, the RTO said.
“We appreciate the ongoing efforts of load-serving entities and states to ensure adequate resources are in place,” Ramey said in a press release.
The forecasted above-normal summer temperatures “can pose some operational challenges,” said Darius Monson, MISO resource adequacy adviser. “It’s worth noting, in a high-load scenario, we are planning to rely heavily on demand response resources.”
The summer reserve estimates include total firm imports, DR and energy efficiency resources based on cleared megawatts in the 2017/18 capacity auction. Non-firm deliveries were excluded from the summer assessment.
“In reality, there might be additional non-firm support,” Monson said.
The RTO also assumed that planned and forced outages would be consistent with the previous five years, and that no MISO South capacity would be stranded in a post-outage situation.
MISO will also hold realistic hurricane simulations with MISO South operators May 23-24 and June 20-21, a first for the RTO, which ordinarily holds less-detailed hurricane drills, according to Marty Sas, senior manager of South reliability coordination. The exercise will start with an intact system and simulate a 31-hour storm that takes nearly 200 transmission lines and 25 generators out of service.
