Maine regulators last week proposed a 15-year phase-out of net metering for current rooftop solar systems and a 10-year limit for new systems.
The proposal came as a part of a rulemaking process that the Maine Public Utilities Commission hopes to complete by the end of the year and implement in 2017.
“In light of changes in the technology and costs of small renewable generation, particularly solar PV, we felt that opening a rulemaking process to consider changes to the rule was the prudent course of action to ensure that all ratepayers are treated fairly,” Chairman Mark Vannoy said in a statement.
The rulemaking also proposes gradually reducing compensation for new solar customers, increasing the size of an eligible customer facility by more than 50%, from 660 kW to 1 MW, and additional consumer protections.
House of Representatives Assistant Majority Leader Sara Gideon, a solar proponent who helped craft a compromise solar power bill that was vetoed by Gov. Paul LePage in April, blasted the PUC proposal.
“Maine needs a comprehensive solar policy. Unfortunately, the PUC’s narrow focus on a single part of the broader solar policy doesn’t help our state’s ability to open new markets that create jobs and lower costs for homeowners, businesses and communities,” Gideon said. “This past session’s solar bill did not simply look at net metering in isolation but was crafted to help our constituents who are clamoring for access to community, commercial and municipal solar. That responsiveness and broad view is why policymaking should be left to lawmakers.”
The net metering review was automatically triggered by a PUC rule after solar exceeded 1% of Central Maine Power’s installed capacity. The utility reported solar at 1.04% at the end of 2015.
ST. PAUL, Minn. — MISO’s 2016 Transmission Expansion Plan recommends 394 projects totaling $2.8 billion.
The preliminary MTEP 16, unveiled at the Sept. 13 System Planning Committee of the Board of Directors, proposes:
114 baseline reliability projects valued at $734 million;
27 generator interconnection projects at $123 million, nine of which will be cost-shared;
One transmission delivery service project at $350,000;
One market efficiency project, the Huntley-Wilmarth 345-kV line project in southern Minnesota projected to cost $81 million; and
251 other projects driven by local needs at $1.8 billion.
Vice President of System Planning and Seams Coordination Jennifer Curran said the top 10 priciest projects in MTEP 16 are evenly distributed between MISO North and MISO South. Spending under MTEP 16 includes more projects than MTEP 15’s 334, but total spending would be $6 million less.
The projects are spread across all MISO quarters, with 33% in MISO South, 39% in MISO West (in parts of northwestern Illinois, Montana, South Dakota and Michigan’s Upper Peninsula and all of North Dakota, Minnesota, Wisconsin and Iowa), 22% in MISO East (in northern Indiana and Michigan’s Upper Peninsula) and the remaining 6% in MISO Central (in parts of Missouri, Illinois, Indiana and Kentucky).
The projects are also varied by type, with 44% of projects dedicated to upgrading substation equipment, 28% dedicated to transmission line upgrades, 20% dedicated to the installation of new transmission lines, 5% dedicated to transformer upgrade and replacement and 3% dedicated to voltage control improvements.
Curran said the lone market efficiency project submitted for approval, the Huntley-Wilmarth 345-kV line, will accommodate wind additions in Iowa and Minnesota. Curran said the cost of the project, which was recommended by North/Central Market Congestion Planning Study and has benefit-to-cost ratio of 2, would be spread 20% across the MISO North and Central regions, with the rest allocated to the local zone. MISO South does not yet share in cost allocations for market efficiency projects.
Board member J. Michael Evans asked why the project wasn’t built 20 years ago if it was meant to handle wind power. Curran said the project will be constructed primarily for new wind buildout.
Board Chair Judy Walsh asked if the MTEP would always involve an expensive bundle of transmission upgrades that chases new generation locations. Vice President of Transmission and Technology Clair Moeller said MISO’s multi-value project category seeks to predict the location where transmission is most needed.
Curran said if approved, MTEP 16 may contain a hitch because the $80.9 million Huntley–Wilmarth line project is located wholly inside Minnesota, which has a right-of-first-refusal statute. Curran said that while the project “by definition is eligible for the competitive transmission process,” Order 1000 and MISO’s Tariff respect state and local laws.
MTEP 16 also includes four economic projects resulting from MISO’s South Market Congestion Planning Study:
An $88 million 230-kV line and substation in southeastern Louisiana with a 1.96 to 3.40 B/C ratio, to be in service by 2022;
The $1.9 million Minden–Sarepta 115-kV line upgrade in northwestern Louisiana with a 1.83 B/C ratio to be in service by 2020;
The $7.6 million Trumann–Trumann West 161-kV line project in northeastern Arkansas with a 13.4 B/C ratio to be in service by 2018; and
The $6.7 million Lakeover 500/230-kV transformer upgrade in southeastern Louisiana with a 1.4 B/C ratio to be in-service by 2020.
Costs for the four projects will be assigned to the local zones that they benefit.
MISO’s Planning Advisory Committee members will vote on the MTEP 2016 report in October. A MISO review of sector feedback will begin in November before the board votes at its December meeting.
“You know, Ernest Hemingway wrote his best novels when he was young, but MTEP keeps getting better. MTEP 16 is better than MTEP 15,” Evans said.
Summer 2016 was the hottest in four years for PJM, but increased energy efficiency and behind-the-meter solar dampened loads.
PJM called 23 hot weather alerts during June, July and August, and Philadelphia, D.C., Richmond, Va., and Louisville, Ky., each recorded more than 30 days above 90 degrees. D.C. led with more than 50 days.
Under Capacity Performance rules, “we want to get these hot weather alerts out early, and probably a bit more frequently,” PJM’s Chris Pilong said.
Nevertheless, the peak load this summer — Aug. 11 — totaled only 151,293 MW, about 4% lower than the 157,509 peak for 2013 (July 18) despite similar temperatures and humidity.
Pilong said the drop likely resulted from conservation efforts, contributions from distributed resources and more efficient air conditioning, light bulbs and televisions.
Performance Assessment Hour Evaluation a Matter of Following Directions
Generators will maximize their revenues and avoid penalties during performance assessment hours by just doing what they’re told, PJM told the Operating Committee last week.
“Here’s the overall concept everyone should be taking away from this: You need to be following your regulation signal,” PJM’s Rebecca Stadelmeyer said.
PJM provides generating units with a signal in real time to follow regarding how much power they should provide. The closer that units stick to providing the requested amount, the better their performance assessment will be — even if the output is below the amount of capacity it cleared in the auction.
“If you’re following the signal to 100%, you will be adjusted to that signal even if we’re keeping that unit down,” Stadelmeyer said.
Stadelmeyer presented several hypothetical examples to explain how regulation bias factors can be used to determine a unit’s set point during an assessment hour. The factors adjust a unit’s assessment measure based on an average over the hour of the assigned regulation PJM sends to the unit. It protects generators from incurring penalties should PJM regulate a unit below its set point and defines bonuses for those regulated above their set points. However, units will not receive any bonus for operating beyond PJM’s scheduled or dispatched level, Stadelmeyer said.
The bias factor, which ranges from -1 to +1, hasn’t been used since PJM transitioned to performance-based regulation, which is more granular.
Preliminary 2017 Capital Budget Focused on Enhancing Reliability
PJM expects to spend approximately $38 million on capital projects in 2017, largely on enhancements and renovations to existing infrastructure. Of the total projected budget, nearly 82% — or about $31 million — is earmarked for software upgrades, application revamps and renovating the Technology Center.
PJM’s Jim Snow presented the proposed budget, which next gets presented to the Members Committee before going back to the Finance Committee for final recommendations. A final proposed budget is scheduled to go before the Board of Managers at its Oct. 17 meeting.
The investment in existing equipment is an increase over the 2016 budget, when $28 million was allocated to the same categories. The remaining $7 million in the proposed budget is allocated to interregional coordination and new products and services, which include funding to implement five-minute market settlements and a more user-friendly public data repository.
Nearly Year-Long Outage Planned for Line Replacement in Va.
Dominion Resources’ Elmont-Cunningham 500-kV line in the company’s north-central Virginia territory will go out of service for about a year for a rebuild starting in October. It is planned to briefly go back into service next summer and be fully in service by June 2018.
Elmont-Cunningham 500-kV Rebuild Map Source: PJM
The line has reached its end-of-life criteria, and continued operation could cause voltage and thermal violations. The outage — which will run from Oct. 23 to June 2, 2017, and then Sept. 6, 2017, to Dec. 30, 2017 — isn’t expected to force any reductions in generation capacity in the area, but it may cause minor thermal overloads and low voltages. Local capacitors will provide reactive support.
“We’re working with [transmission owners] to find some potential switching solutions that could resolve the issues,” PJM’s Lagy Mathew said.
ComEd to Remove Cordova Stability SPS
The special protection scheme (SPS) ensuring stability at the Cordova Energy Center is no longer required now that all 345-kV circuit breakers at Commonwealth Edison’s Quad Cities Station 4 have been upgraded to independent pole-operated devices, ComEd said
The system trips combustion-turbine units at the center for a three-phase fault within a roughly 3-mile zone of Quad Cities that persists for more than six cycles. With the upgrades, the generators are now stable for all faults specified by ComEd and PJM criteria, and the severity of a breaker failure following three-phase faults is reduced.
The SPS is targeted for removal by the end of 2016. The units also trip from Quad Cities’ multiline outage unit trip scheme, which will remain active.
A proposed Rhode Island power plant has lost its planned cooling water source, and its developers are asking state siting officials for another month to secure a new one.
Invenergy said the Pascoag Utility District, which had signed a letter of intent to provide water to the $700 million, 1,000-MW Clear River Energy Center dual-fuel power plant, withdrew from the agreement last month.
The company had proposed reopening a PUD well that was closed in 2001 because of contamination from a nearby underground storage tank. The municipal utility backed out, citing its determination that a proposed water treatment system is inadequate to protect its aquifer. A backup plan to use water from the nearby Harrisville Fire District also was turned down.
As a result, Invenergy asked the Rhode Island Energy Facility Siting Board on Sept. 9 for a 30-day extension that would push the plant’s hearing schedule into mid-November.
“Our proposal had been that we would put that water through our own treatment system to clean up that well,” John Niland, Invenergy’s development director, told the ISO-NE Consumer Liaison Group meeting on Thursday. “So we’re currently looking to find an alternative to that source, and we’re hoping to provide folks with more clarity on what our supply will be in the near future.”
The Town of Burrillville, where the plant is located, last week asked the board to dismiss Invenergy’s application and close the case.
“Invenergy’s application currently contains no information at all about a proposed water source. The application therefore cannot be evaluated in a meaningful way without this information,” the town wrote.
The power plant’s daily water needs would vary from about 100,000 gallons under normal conditions to nearly 1 million gallons, according to its permit application.
Several state agencies weighed in on the plant with advisory opinions filed with the siting board Sept. 12.
The Public Utilities Commission said the plant would support the region’s reliability needs and also hold down capacity prices. Only Commissioner Herbert F. DeSimone Jr. signed the opinion, because the other two commissioners had to recuse themselves.
Chairperson Margaret E. Curran also heads the EFSB, and Commissioner Marion Gold, who was appointed in the summer, previously served as commissioner of the state Office of Energy Resources.
The state energy office said the plant would help meet Rhode Island’s reliability, energy efficiency and cost goals and would not prevent the state from meeting the carbon reduction goals of the Resilient Rhode Island Act.
The Department of Environmental Management said Invenergy failed to provide enough information about the impacts on fish and wildlife and raised questions about noise and air quality. The lack of information about a water source and other unfinished environmental reviews means the agency is not yet able to render an opinion, the DEM said.
The plant would require clearing more than 121 acres of forestland in northwestern Rhode Island. The site is adjacent to an Algonquin Gas Transmission pipeline and compressor station and a National Grid right of way needed to connect it to the ISO-NE grid.
Invenergy says the plant will reduce emissions by replacing older, less efficient units. It will also add capacity to the constrained Southeast Massachusetts-Rhode Island transmission zone. One 500-MW unit is scheduled to be in service in June 2019 and the second a year later. The first unit was successfully bid into the ISO-NE Forward Capacity Auction for the 2019/20 commitment period.
ACC to Hire Outside Counsel to Represent Commissioner
Burns
The Corporation Commission voted to hire an outside attorney to represent Commissioner Robert Burns, who is being sued by Arizona Public Service over his effort to investigate the utility’s political spending.
Burns issued subpoenas to APS and its parent company, Pinnacle West Capital, last month to determine whether the company is the source of millions in funding that helped to elect two Republicans to the ACC in 2014.
The utility has filed a motion to quash the subpoenas and to charge Burns for its attorney fees. APS argues that state law does not require the utility to disclose the information Burns is seeking. Commission staff attorneys say they can’t represent Burns because of conflict-of-interest concerns.
San Diego Gas & Electric and Southern California Edison have arranged nearly 65 MW of energy storage to be ready by January in response to a call from state regulators to prepare for winter power shortages because of the loss of the Aliso Canyon natural gas storage field.
SDG&E lined up two lithium-ion battery storage facilities that total 37.5 MW, and SoCalEd hired developers to build 27 MW of energy storage. The Public Utilities Commission is expected to approve the contracts soon.
The deals illustrate the rapid rise of the energy storage market in the state. “What this really shows is how quickly we can add diversity to the fleet in these critical areas,” said Alex Morris, a spokesman for the California Energy Storage Alliance.
Six Cities File Protest Against Diablo Canyon Plan
A coalition of six San Luis Obispo County cities have filed a protest to Pacific Gas and Electric’s plans to decommission the Diablo Canyon plant.
The cities of San Luis Obispo, Arroyo Grande, Atascadero, Morro Bay, Paso Robles and Pismo Beach have jointly filed a request with the Public Utilities Commission to intervene in the proceedings to ensure the agency formally considers their concerns about the local economic, environmental and emergency preparedness impacts of the closure.
The coalition says it is not opposed to the shutdown but is seeking guarantees about the cleanup and future uses of the plant site.
Xcel Energy has reached a settlement with the Public Utilities Commission and intervenors that will speed up the development of the utility’s 600-MW wind project and a 125-mile transmission line.
The Rush Creek Wind Project, proposed across five eastern counties, would rank as the state’s largest wind facility, boosting wind generation capacity by 20%. Xcel estimates Rush Creek will save customers $400 million over its 25-year life and remove an estimated 1 million tons of carbon from the atmosphere each year.
Xcel needs to start construction on the $1 billion wind project this year to qualify for $443 million in federal renewable energy tax credits. If the start of construction is delayed until 2017, Xcel stands to lose $125 million in credits.
Clean Line Energy Partners and the Commerce Commission are appealing a state appellate court’s reversal of the Rock Island Clean Line’s approval by the commission. The state Supreme Court will now determine the future of the $600 million project.
The International Brotherhood of Electrical Workers, the Natural Resources Defense Council and Wind on Wires joined the appeal of the 3rd District Appellate Court’s decision. The court ruled last month that the project did not satisfy the definition of public utility under the state’s Public Utilities Act and should not have received a certificate of public convenience and necessity. That certificate allowed the project to use eminent domain to secure a route for the 500-mile HVDC line.
Commonwealth Edison, the Illinois Landowners Alliance and the Illinois Farm Bureau had appealed the ICC’s approval.
The Public Service Commission last week approved the merger of Empire District Electric and Liberty Utilities, a subsidiary of Canada-based Algonquin Power and Utilities.
As part of a settlement with the Division of Energy, Empire has agreed to file an application for an energy efficiency portfolio under the state’s Energy Efficiency Investment Act, which encourages utility companies to invest in energy-efficient programs. The company has also agreed to consider a community solar program and microgrid technology.
To close the deal, Empire also agreed to settlements with the Office of Public Counsel, the City of Joplin, several labor unions and Empire retirees.
Lincoln Electric System says that demand for electricity has flattened, forcing the public utility that serves the state’s capital to adjust its rate structure to gradually increase the fixed amount customers pay each month and to decrease its dependence upon revenue from kilowatt-hour usage.
Demand is expected to remain flat for the next five years, LES said in a report to credit rating agencies earlier this year, as customers embrace more efficient behavior and equipment.
“As an industry, a lot of us missed this dramatic drop in demand growth,” LES Vice President of Power Supply Jason Fortik told the Lincoln Journal Star. “It wasn’t just an LES thing. As the utility industry, we’re out incenting people to be more efficient and place less demand on our system. I suppose we shouldn’t be surprised when it actually starts to occur.”
Several offshore wind industry companies, academics and environmental organizations have formed a coalition to encourage the development of offshore wind farms on the state’s coast.
The newly formed New York Offshore Wind Alliance wants to push the state to develop 5,000 MW of offshore wind by 2030. The coalition is a project of the Alliance for Clean Energy New York and includes Deepwater Wind, DONG Energy, the National Wildlife Federation, the Natural Resources Defense Council and the Sierra Club.
The Public Service Commission has scheduled a hearing on the proposed 300-MW Glacier Ridge Wind Farm in Barnes County.
The $375 million wind farm would be sited on 34,450 acres about 5 miles east of Valley City and have up to 87 turbines, according to preliminary plans. The public hearing is set for Sept. 27 at Valley City State University.
The Public Utilities Commission approved the request of developer Prevailing Winds to withdraw its application to build a 100-turbine wind farm near Avon.
The company pointed to a public hearing last month that drew about 300 people to a school gym, with 22 speaking, mostly in opposition to the project.
“The Prevailing Winds project is a community wind project and community is very important to the Prevailing Winds investors and board of governors,” the company wrote in explanation. “Unfortunately, misinformation has been circulated about the project.” It said the application withdrawal would allow the company “to better inform the community on the project and allow Prevailing Winds to revisit its options regarding the project.”
A study conducted by the Institute for Energy Economics and Financial Analysis and published by Public Citizen found that at least seven of the state’s 19 coal plants, representing more than 40% of the total coal-fired capacity in ERCOT, are in danger of closing.
The analysis paints a familiar picture: The growth of renewable energy, low natural gas prices and increased environmental regulations are making the coal plants financially inviable. They will likely lose more than $160 million a year, according to the report.
The seven plants, totaling 8,100 MW, are Luminant’s Big Brown, Martin Lake and Monticello; Dynegy’s Coleto Creek; and the publicly owned Fayette, Gibbons Creek and J.K. Spruce.
ST. PAUL, Minn. — The MISO Board of Directors’ Nominating Committee has settled on three candidates to fill the three seats up for election for three-year terms beginning in January. (See “Board Member Search Down to 6 Candidates,” MISO Advisory Committee Briefs.) Director Michael Curran said MISO will consider:
Todd Raba, who is preparing to exit Twenty First Century Utilities in D.C., a startup company that invests in regulated utilities looking to modernize. Raba also served as CEO of Berkshire Hathaway’s Johns Manville and president of its MidAmerican Energy. He is a former CEO of GridPoint, an energy management company, where he remains a board member. He has a bachelor’s degree in forestry from the University of Vermont.
H.B. “Trip” Doggett, a former ERCOT CEO who has more than 38 years of experience in the electricity industry. While employed with Duke Energy, Doggett helped to launch CAISO. Doggett also holds a seat on the advisory board of the Texas A&M University Smart Grid Center. He holds a bachelor’s in engineering from the University of North Carolina at Charlotte.
Barbara Krumsiek, former CEO of Calvert Investments, a $14 billion asset management firm. Krumsiek began her career in investments more than 40 years ago, and her board experience includes a recent, nine-year stint on Pepco Holdings Inc.’s board of directors. Krumsiek holds a master’s in mathematics from New York University.
Board Chair Judy Walsh and directors Michael Evans and Paul Feldman will reach MISO’s term limit Dec. 31. MISO enacted a limit of three consecutive three-year terms last year.
“I think this is a great slate of new directors,” Walsh said.
MISO Senior Vice President of Compliance Services Stephen Kozey said voting on the candidates began immediately and will continue through Oct. 24. Results will be announced at the October Informational Forum. Kozey said 25% of MISO members need to cast ballots to reach a vote quorum.
Additionally, Curran was elected to lead the board as chairman in 2017, replacing Walsh.
MISO Projected to End Year Close to Budget
MISO management said the RTO is projected to spend between $223.9 million and $226.1 million of its $225 million 2016 budget by the end of the year.
The RTO’s actual year-to-date spending of $149.3 million is under budget by $1.3 million (0.9%).
“We anticipate being within a half percent of the budget by the end of the year,” Vice President of Strategy and Business Development Wayne Schug said during a finance report at the Sept. 15 board meeting. Schug stepped in to deliver the report after former Vice President of Finance Jo Biggers left MISO unexpectedly last month. (See Vice President of Finance Biggers Exits MISO.)
Schug also said MISO is $4.7 million, or 18.6%, under budget year-to-date on its $31 million capital projects spending plan.
Director Baljit Dail expressed concern that not enough capital projects were going to be completed. “I struggle to see how you’re burning through $4.7 million by the end of the year,” he said.
Schug said although some capital spending will be deferred into 2017, MISO will come closer to its capital spending target in the fourth quarter. “We’re going to get closer back to budget but not get all the way back. We’re probably going to be under budget by $0.5 million,” he told the board.
“These numbers are somewhat lagging, [but] because it’s the third quarter, I don’t think we need to be overly concerned. I know you’ll make these adjustments by the end of year,” Director Phyllis Currie said.
MISO has spent $700,000 on NERC’s Critical Infrastructure Protection v.5 cybersecurity compliance and its competitive retail solution for the capacity auction. By year-end, the number is expected to reach $1.2 million.
In response to a question from Currie, Schug said MISO is still considering whether to switch from a 501(c)(4) organization to a 501(c)(3) organization, a topic that was broached at the June board meeting. (See “MISO on Budget in Mid-2016, Considers Becoming 501(c)(3),” MISO Board of Directors Briefs.)
For Now, MISO Bylaw Changes Minimal
Director Thomas Rainwater said the board is making revisions to MISO’s Bylaws/Transmission Owners Agreement that are largely “cleanup” from when the board increased to nine members from seven.
Rainwater also said the board’s Human Resource Committee decided to postpone making changes to pre- and post-service restrictions on directors. MISO is considering reducing the current two-year pre- and post-service prohibition in a utility or the wholesale energy markets. (See “MISO Asks Members to Consider Bylaw Changes,” MISO Informational Forum Briefs.)
Board Wants to Quantify IT Benefits
Dail said the board’s Technology Committee has begun investigating the return on investment for MISO’s information technology spending. Walsh said she would like to see tracking of IT investment returns in an accounting report. Currie called for a more formalized process altogether on budgeting.
Other items also were addressed at the board meeting:
CEO John Bear asked stakeholders to offer ideas for “hot topics” to discuss during in-person Advisory Committee meetings in 2017. Bear said next year’s topics could include a review of the competitive transmission process, transmission cost allocation on multi-value projects and the “disconnect” on the interconnection queue.
Organization of MISO States President Sally Talberg said OMS is working on its own seams policy. Talberg also said that because too few generator owners and operators are completing MISO’s Winter 2016/17 Generator Fuel Survey, OMS will provide reminders to MISO members starting next month. The survey data are used in the yearly fuel assurance report. “With OMS as an intermediary, it’s going to be critical to work together,” Talberg said.
Advisory Committee Chair Audrey Penner wants to include a volunteer event in MISO’s quarterly Board of Directors Week. Penner said when the committee meets in-person, it would be good for members to spend a few hours volunteering with local nonprofits.
SPP says improved wind forecasting and coordination with gas pipelines have the RTO well prepared for the coming winter.
Iced wind turbine Source: Kelly Aerospace
SPP engineer Jon Langford said during the RTO’s annual winter preparedness emergency operations call last week that its wind forecaster, Energy & Meteo Systems, has developed a full icing forecast. The forecasting tool, to be delivered in November, compensates for freezing temperatures that shut down wind turbines’ directional systems.
“The wind farm works, but the equipment that turns the turbine [in the direction of] the wind stops working,” Langford explained.
He said SPP’s winter peak load is expected to near 38,000 MW, “if we get close to what we did last year.” That number is less than half of the footprint’s 83,465 MW of capacity.
The winter emergency operations plan is available online but requires a password.
C.J. Brown, manager of SPP’s balancing-authority functions, reminded stakeholders of the Oct. 1 switch to the new gas-day timeline as a result of FERC Order 809. (See “New Gas-Day Nom Process on Track for Oct. 1 Go-Live,” SPP Briefs.) Market participants will now submit their bids and offers by 9:30 a.m. instead of 11 a.m.
“From SPP’s perspective, this presents a good step in the direction where we can be a little more efficient and a little earlier,” Brown said. He also said the RTO has increased its communications with gas suppliers.
“We sure don’t want to rest on our capacity margin and our infrastructure,” Brown said.
Jeff Johnson, a meteorologist for Schneider Electric, predicted below-normal temperatures this winter for SPP’s footprint. He said a slight warming trend in February would be followed by more cool weather in March.
Johnson said the Pacific Decadal Oscillation (PDO), a pattern of oceanic climate variability extending from Alaska to Hawaii, will result in a winter similar to the 2013-14 and 2014-15 seasons.
The PDO “tends to produce a more northerly component to the jet stream,” he said. “That helps deliver more Arctic air out of Canada into the central part of the country.”
ST. PAUL, Minn. — MISO stakeholders last week continued their critique of the RTO’s proposed Competitive Retail Solution.
MISO’s proposal and the broader issue of resource adequacy were the “hot topic” at last week’s Advisory Committee discussion moderated by consultant Robert Gee.
Gee began by asking sectors if MISO’s separate forward auction for retail-choice zones was reasonable — or even necessary.
Dynegy’s Mark Volpe said the Independent Power Producers sector believes that a serious problem exists, pointing to the forecasted generation shortfalls in Illinois and Michigan and the 1.9 GW of generation that’s currently pseudo-tied out of Illinois into PJM.
5 GW Departing
“You’ve got 5 GW of generation in southern Illinois — if you count the retirements and suspensions — that’s departing MISO. That’s huge. … It’s clear evidence that a problem exists and has existed for years that needs to be addressed yesterday,” Volpe said.
The IPP sector submitted comments suggesting MISO conduct voluntary forward auctions for regulated states and a “mandatory auction for retail-choice load.”
The Transmission-Dependent Utilities sector has not reached consensus on whether MISO’s forward auction addition is necessary, WEC Energy Group’s Chris Plante said. “I think we have a plurality of members who are opposed to the Competitive Retail Solution,” Plante said. He added that incremental changes could be made, including raising the cost of new entry to two or three times its current amount.
Northern Indiana Public Service Co.’s Paul Kelly said the Transmission Developers sectors is not answering whether the CRS is needed anymore, as it’s clear MISO will file the auction redesign for FERC approval anyway.
“What we’re willing to say as a sector is that the concerns we had have been addressed by MISO, and we’re appreciative of that,” Kelly said. “It’s not as if a forward auction hasn’t existed in America, so we’re not blazing a new trail.”
‘Totally Dysfunctional’
Madison Gas and Electric’s Megan Wisersky, of the TDU sector, said just because a forward auction has been done elsewhere, doesn’t mean it’s been done correctly.
“The eastern forward capacity markets are completely, totally dysfunctional,” Wisersky said. “More and more people are dragged into it, kicking and screaming. We’re not solving it by chasing this ephemeral idea that changing capacity markets are the way to fix it. If you really want to think about it, capacity isn’t even a real product — energy and ancillary services are.” (See related story, Monitor: NYISO Needs Locational Focus, Flexibility — not Forward Capacity Market.)
The Illinois Industrial Energy Consumers’ Jim Dauphinais, speaking for the End-Use Customers, reminded the Advisory Committee that Lower Michigan and Illinois will pay for what is decided. Dauphinais said he was not convinced that a major market change was needed at all and that MISO’s current proposed market rules are “unnecessarily complicated.”
“It treats retail load like an outcast,” Dauphinais said. He said the Independent Market Monitor and MISO’s hybrid solution, which kept both merchant and regulated load on the same prompt auction schedule and applied a sloped demand curve to merchant load, was more reasonable.
Volpe said MISO’s Board of Directors and management should pay attention to the Monitor’s “deep-seated” concerns on price formation in a bifurcated market.
The Public Consumer Group sector voiced concerns that generators in regulated states could voluntarily bid into the forward auction, making them unavailable for local customers. The sector called on MISO to conduct annual testing to confirm actual available capacity amounts.
The Power Marketers sector said moving the auction for competitive areas three years out gives market participants time to plan and budget. The TDU sector countered that argument, claiming MISO has changed the capacity process so often year to year that it has become difficult for utilities to get their bearings. “MISO’s processes in this area have been changing every year since 2009, and the lack of consistency and predictability from year to year creates problems for utilities trying to do their own planning,” the sector wrote.
‘Slippery Slope’ Fear
After multiple stakeholders called the forward auction “a slippery slope,” MISO Director Paul Bonavia asked why stakeholders believed the forward auction construct would eventually cross into traditionally regulated areas.
Once filed with FERC, “I cannot imagine … the possibility that MISO … would apply this proposal to the entire footprint,” Volpe said.
“FERC is not shy about pushing jurisdictional boundaries,” Wisersky fired back.
Matt Brown, representing the Transmission Owners sector, said that while the risk of spreading applies to any new regulation, his sector wasn’t worried MISO would apply a PJM-style forward capacity market to the entire footprint.
“Last I checked, MISO wants to be an RTO five years from now,” NIPSCO’s Brown said, referring to the voluntary nature of RTO membership. “I think MISO has done a good job recognizing that what Michigan and Illinois needs is very different from what the rest of the market needs.”
Bonavia said that while the board wasn’t going to “jump in and start writing Tariff language,” it has heard the concerns.
“It doesn’t sound like — to nobody’s great surprise — that there’s a lot of accord on the Competitive Retail Solution. But I’ll say this as one director: It feels that there’s a pretty strong sense to assure it’s a regional solution that doesn’t bleed over or create the slippery slope that sucks other states into it.”
Awaiting the Details
Indiana Utility Regulatory Commissioner Angela Weber, representing the State Regulatory sector, said she is not sure whether the proposal is reasonable because details, such as the shape of the forward demand curve, have not yet been provided.
Weber said she wanted to make sure that the demand curve is shaped so both competitive and regulated areas in MISO achieve equal reliability and uphold the one-day-in-10-year loss-of-load expectation.
Comments from the State Regulatory sector urged the RTO to “keep in mind that resource adequacy within MISO is largely a state and local responsibility” and said it was “imperative that the current Competitive Retail Solution is shown not to impact existing state and local authority and processes.”
A day later at the MISO board meeting, Director Thomas Rainwater wondered if the problem in Southern Illinois was being “overstated” by the RTO.
Richard Doying, executive vice president of operations and corporate services, said that whether or not the predicted shortfall in the Organization of MISO States survey is accurate, new generation that “no one is building” will be needed in Zone 4. Efficient pricing achieved through the forward auction, Doying said, will encourage investment in new generation.
CAISO paid congestion revenue rights holders $27 million more than it took in from CRR auctions during the first half of the year, according to the ISO’s Department of Market Monitoring.
That equates to 63 cents in auction revenues for every dollar paid out, leaving California electricity consumers to foot the difference — which mostly goes to speculators, the Monitor says.
The department wants the ISO to address the issue by eliminating or reforming the auction process.
“There’s a shortfall between payments and revenues in the auction, and this money is really ultimately paid by the ratepayers in the market,” Gabe Murtaugh, a department senior analyst, said during a Sept. 14 call to discuss the department’s second-quarter market performance report.
The graph shows that payments to congestion revenue rights holders consistently exceed the amounts taken in by the ISO during auctions.
The Monitor reasons that ratepayers — who ultimately bear the costs for transmission access charges paid by load-serving entities — are entitled to receive the revenues from transmission.
“When auction revenues are less than the payments transferred to other entities purchasing congestion revenue rights at auction, the difference between auction revenues and congestion payments represents a loss, which is paid out from the day-ahead congestion rent,” the department’s quarterly report explained. “The losses therefore cause ratepayers, who ultimately pay for the transmission, to receive less than the full value of their day-ahead transmission rights.”
Financial traders are the biggest beneficiaries of the current CRR market design, the Monitor has found. During the first half of 2016, those companies made $22.7 million in profits, more than doubling their investments as they paid 49 cents into the ISO’s auctions for every dollar earned.
Over the same period, power marketers and generators took in about $3.9 million and $800,000, respectively, paying 82 and 85 cents for every dollar of congestion revenues earned.
This year’s mismatch extends a pattern that has persisted for nearly five years, Murtaugh said. Since 2012, CRR payments have exceeded auction revenues by more than $500 million.
It all adds up to a need for a change in how the ISO administers the CRR process, the Monitor contends.
One specific recommendation is that the ISO should end the practice of auctioning off excess transmission capacity to third parties after LSEs have received their CRR allocations.
“With this approach, the ISO could still run a market for congestion revenue rights,” the Monitor said. “However, this market would be run only with bids voluntarily submitted by various participants willing to essentially buy or sell congestion revenue rights.”
In other words, the only CRRs available to market would be those allocated to LSEs. CRRs would only be sold if there was a market participant willing to take on the obligation to pay congestion revenues at the market clearing price, thereby reducing ratepayer exposure to market shortfalls.
“In this market, any entity that values hedging against locational price differences, such as generators or marketers, could submit bids to purchase congestion revenue rights,” the Monitor said. “Financial entities, other participants willing to sell hedges or entities wishing to speculate on locational price differences could submit bids to sell congestion revenues rights.”
The Monitor said it is prepared to work with the ISO and stakeholders on additional options to change the CRR market and noted that the ISO’s management is considering adding the issue to its stakeholder initiative catalog this fall.
PJM is trying to usurp the Independent Market Monitor’s authority to regulate fuel-cost policies and consequently increasing market participants’ ability to exercise market power, the Monitor argued in a protest Friday (ER16-372).
PJM’s proposed plan for evaluating fuel-cost policies, filed Aug. 16, “would substantively change the roles of PJM and the Market Monitor in the review of offers for market power in a manner inconsistent with the Tariff’s specifications of roles,” IMM staff wrote. “Participants will have the ability and incentive to submit inaccurate cost-based offers.”
The debate over the rules governing fuel-cost policies stems from a 2015 FERC order requiring the RTO to allow day-ahead offers that vary by the hour and the ability of generators to update offers in real time. (See Heeding Stakeholders, PJM Reduces Proposed Fuel-Cost Penalties.)
The Monitor said that daily offers limited generators’ “ability to exploit real-time constrained conditions.” The switch to hourly offers, it said, requires “increased rigor” in mitigation design and the implementation of the three pivotal supplier test in addition to fuel-cost policies.
Other responses to PJM’s filing largely supported the RTO’s effort to develop hourly offer rules, but they differed on how fuel-cost policies should be handled and what role the Monitor should play.
‘Define the Roles’
The Pennsylvania Public Utility Commission and the Delaware Public Service Commission said in a joint filing that “PJM’s [fuel-cost policies] proposal undermines the Independent Market Monitor’s role in detecting and addressing market power concerns” and urged FERC to adopt the Monitor’s standards.
In a joint filing supporting PJM’s proposal, American Electric Power, Dayton Power and Light, FirstEnergy, Duke Energy, Buckeye Power and the East Kentucky Power Cooperative asked the commission to “plainly define the respective roles” of PJM and the Monitor in the process.
“Market sellers are squarely in the middle of a perfect storm created by ambiguous governing documents, new commission directives and a complete lack of clarity concerning the role of the IMM,” the group wrote. “The result is untenable risk associated with submitting cost-based offers without approved fuel-cost policies. Failing to act timely, or at a minimum to preserve the status quo while the commission deliberates, will perpetuate an already fraught state of affairs.”
Dominion Virginia Power reiterated those sentiments in its filing, asking “that the commission establish final authority with one entity.”
The Organization of PJM States Inc. asked FERC to view the docket in a larger context. “Discounting the IMM’s current role could provide a signal to resources that they would no longer be held fully accountable to IMM oversight, potentially eliminating the proper incentive to submit accurate cost-based offers,” OPSI wrote. “The commission should consider the broad implications of approving any filing that usurps the IMM’s existing market power authorities.”
The American Petroleum Institute focused on the structure of the policy itself, saying the rules “need to provide generators some degree of flexibility to procure fuel in the lowest cost manner.” Specific rules about how to procure fuel “may restrict generators in a way that could lead to higher consumer costs.”
API also protested PJM’s proposal that all policies on which the RTO and the Monitor can’t agree on should be referred to FERC’s Office of Enforcement. The group called for a dispute-resolution process instead.
No ‘Bright Line’
The PJM Power Providers Group agreed procurement practices shouldn’t be dictated. “The purchasing of fuel for power generation is a complicated and thoughtful piece of any generator’s business strategy,” P3 wrote. “PJM and the IMM should not attempt to replicate the market or impose a formulaic evaluation on generators, as such a task would prove nearly impossible and more likely lead to chaos during times of system stress.”
Dominion agreed that PJM’s proposal is too restrictive. Fuel-cost policies should not be “a pre-existing, bright-line formula for all market conditions,” Dominion wrote. “This expectation is unrealistic and made more unreasonable by PJM’s failure to first require consultation regarding suspect cost-based offers before they are deemed to be not in compliance with a resource’s fuel-cost policy.”
The company called for a system similar to ISO-NE’s, in which its Internal Market Monitor estimates a competitive offer that creates a “reference price” against which all market offers are compared. It also asked that PJM’s proposed penalty — requiring units without an approved policy to submit an offer of $0 — be replaced with a less punitive option and that companies not be required to submit a policy for each type of fuel at a unit, estimating it would need to maintain more than 100 separate policies.
No matter what FERC’s decision, it should be made quickly, P3 urged. “Every winter that passes without hourly offer flexibility is a winter in which the market is less efficient, suppliers are exposed to inadequate cost recovery and reliability is potentially” compromised, the group wrote.
Monitor’s Proposal
The Monitor proposed a clear delineation between the responsibilities of PJM, which would conduct a compliance review with IMM input, and the Monitor, which would conduct a market-power review without PJM involvement. The Monitor said its review will ask that policies are algorithmic, verifiable and systematic. They would need to show:
a set of defined, logical steps;
a fuel price that can be calculated by the Monitor after the fact with the same data available to the generation owner at the time the decision was made and documentation for that data from a public or a private source; and
a standardized way for calculating fuel costs including “objective triggers” for each method.
PJM proposed a joint review that it would control with input from the Monitor. The RTO’s proposal creates “a critical flaw” because it doesn’t “preserve the Market Monitor’s role in market-power reviews and to tie the consequences for noncompliance to that review,” the Monitor said.
San Diego Gas & Electric and Southern California Edison have arranged nearly 65 MW of energy storage to be ready by January in response to a call from state regulators to prepare for winter power shortages because of the loss of the Aliso Canyon natural gas storage field.
A coalition of six San Luis Obispo County cities have filed a protest to Pacific Gas and Electric’s plans to decommission the Diablo Canyon plant.
Xcel Energy has reached a settlement with the Public Utilities Commission and intervenors that will speed up the development of the utility’s 600-MW wind project and a 125-mile transmission line.
Clean Line Energy Partners and the Commerce Commission are appealing a state appellate court’s reversal of the Rock Island Clean Line’s approval by the commission. The state Supreme Court will now determine the future of the $600 million project.
The Public Service Commission last week approved the merger of Empire District Electric and Liberty Utilities, a subsidiary of Canada-based Algonquin Power and Utilities.
Lincoln Electric System says that demand for electricity has flattened, forcing the public utility that serves the state’s capital to adjust its rate structure to gradually increase the fixed amount customers pay each month and to decrease its dependence upon revenue from kilowatt-hour usage.
Several offshore wind industry companies, academics and environmental organizations have formed a coalition to encourage the development of offshore wind farms on the state’s coast.
The Public Service Commission has scheduled a hearing on the proposed 300-MW Glacier Ridge Wind Farm in Barnes County.
