FERC last week revoked authorization for Berkshire Hathaway Energy subsidiaries to sell wholesale power at market-based rates in four neighboring balancing authority areas in the West.
The commission ruled that Berkshire failed to prove that its affiliates — which include PacifiCorp, NV Energy and 19 other generating entities — do not exercise horizontal market power in the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern Energy areas (ER10-2475, et al.).
“In the absence of reliable delivered price test (DPT) analyses rebutting the presumption of market power, we find that the continuation of the Berkshire [subsidiaries’] market-based rate authority in these four balancing authority areas is not just and reasonable,” the commission said.
Berkshire Hathaway Energy’s subsidiaries will be restricted from selling at market-based rates in the PACE, PACW, NWMT, and IPCO areas represented on the map.
FERC ordered the companies to file revised tariffs limiting their market-based sales to regions outside the four areas within 30 days. The companies must also issue refunds for the period between January 9, 2015, and April 9, 2016.
The decision left intact Berkshire market-based rate authority in the Arizona Public Service, Bonneville Power Administration, Los Angeles Department of Water and Power, Western Area Power Administration Colorado-Missouri and WAPA Lower Colorado balancing authority areas, as well as in CAISO.
Berkshire companies are already prohibited from selling power at market-based rates in the NV Energy area covering most of Nevada.
FERC’s ruling marks the second such setback for Berkshire in less than a month. In May, the commission declined to rehear a 2015 decision that prohibits PacifiCorp and NV Energy from offering energy into the Western Energy Imbalance Market (EIM) at prices above default energy bids because of concerns about the companies’ combined market power. (See Berkshire Denied Rehearing on EIM Market Power.)
The June 9 order stems from Berkshire’s 2013 acquisition of NV Energy, which put Warren Buffett’s energy conglomerate in control of more than 19 GW of generation serving states throughout the western U.S. In light of the acquisition, the commission instituted a Section 206 proceeding requiring the Berkshire companies to submit evidence that their market-based rate authority remained valid in the four areas in question.
While the Berkshire companies failed the indicative “pivotal supplier” and “wholesale market power” screens for initially assessing horizontal market power in the four areas, FERC policy allows a power supplier to rebut that presumption by performing a more thorough DPT analysis. The DPT factors in native load commitments to determine a supplier’s “available economic capacity” — energy available for offer in the open market — over 10 different seasons and load conditions. The analysis must also consider the load commitments for and available supply from other generators in the region.
FERC’s decision to revoke Berkshire’s market-based rate authority ultimately rested on what the commission called a “flawed” DPT analysis from the company. The commission focused in particular on Berkshire’s failure to calculate unique season and load levels for each of the four areas, instead relying on assumptions based on data for only the PACE area.
One example cited by the commission: “In the Idaho Power balancing authority area, Idaho Power would likely not be a competing supplier in certain season/load levels in the [available economic capacity] analysis, even though it is listed as having the most competing capacity in many of the season/load levels.
“The Berkshire [companies] are attempting to demonstrate that they do not have market power in four different balancing authority areas,” the commission continued. “In order to do so, the DPT analyses submitted by the Berkshire [companies] should have used inputs, assumptions and facts appropriate to the unique characteristics of each balancing authority area when studying that particular area.”
As a result of the decision, the Berkshire companies must each submit tariff revisions providing for default cost-based rates for the PACE, PACW, Idaho Power and NorthWestern areas — or inform the commission of their intention to use any cost-based tariff currently on file.
PacifiCorp — the largest Berkshire entity affected by the ruling — told RTO Insider that it continues to review the order but expects “limited impact” because of the small number of transactions involved.
“The bulk of PacifiCorp’s wholesale sales occur at trading hubs that are outside the areas affected by the order, or within the Energy Imbalance Market, which is also not impacted by the order,” spokesman Bob Gravely said.
Asked whether the ruling would strengthen the case for PacifiCorp to join CAISO in an effort to reduce market power concerns, Gravely said, “This ruling shouldn’t impact one way or the other the decision to join a regional ISO. Issues such as governance and ensuring overall net benefits for customers are what will ultimately drive that decision.”
“There will be a point where we stop asking questions,” FERC’s Arnie Quinn promised during a panel discussion at the Energy Bar Association’s Annual Meeting last week.
That point will come after the commission reviews the transcript of last month’s technical conference on the subject and the post-conference comments it is now soliciting.
The commission’s questions started in 2008, when it asked the RTOs to make proposals to reduce interconnection backlogs (AD08-2). The grid operators offered a number of changes, including clustering interconnection studies by location and establishing development milestones to weed out projects not progressing toward commercial development.
But the changes haven’t ended developers’ complaints about study delays or the difficulty in predicting interconnection costs. At the technical conference, transmission operators countered that the delays are caused by the high number of speculative interconnection requests, which force them to conduct restudies when a project drops out of the queue. (See Generators, Tx Operators Spar over Interconnection Processes Before FERC.)
After that, the commission could respond with a prescriptive rulemaking, a policy statement — which wouldn’t require transmission operators to make any changes — or a hybrid of the two, said Quinn, director of FERC’s Office of Energy Policy and Innovation.
“The difficulty with this topic … is it’s fairly straightforward to define the problem,” Quinn said. “Identifying the solutions that are going to work everyplace — that’s the harder nut to crack.”
Incremental, Comprehensive Changes Sought
Last month’s conference was called in response to a rulemaking request by the American Wind Energy Association, which argued that existing interconnection rules are outdated and discriminatory.
Panel moderator John Moore, of the Natural Resources Defense Council, opened the EBA session last week by quoting from Invenergy’s testimony at the conference, in which the company related its experiences on the length of the interconnection processes: SPP (one year); PJM (two years); CAISO (two and a half years); MISO (“has seldom taken less than three years”); and NYISO (as long as six to seven years). “An interconnection process lasting three years or more can kill even the most serious of projects,” Invenergy’s Kris Zadlo said.
Quinn said he concluded from the conference testimony that developers are seeking both incremental improvements — including more access to models and the ability to self-construct interconnection facilities — and more comprehensive changes.
The comprehensive proposals are more controversial, Quinn said, citing a call for closer coordination between the transmission planning and the interconnection processes. “Instead of serially studying a bunch of projects over time, just identify an area on the transmission system where you’ll need some upgrades. Using the transmission planning process to do that might smooth the interconnection process,” Quinn explained.
The controversy? “Transmission is usually paid for by load; interconnection upgrades are typically paid for by the interconnection customers. So that can look like a cost shift, and — especially where the states are involved — they might want a say in the degree to which that cost shift occurs,” Quinn continued.
Another suggestion is to cap interconnection cost estimates at an early stage in the interconnection process, as CAISO is doing. “If the interconnection customer can get some information on cost that can feel firm, the interconnection customer can keep moving on,” Quinn said.
Panelist Mason Emnett, a federal regulatory attorney for NextEra Energy, had his own wish list. He said he would like RTOs to provide developers with information on their overloaded facilities. “Our transmission engineers can use that to go back to developers to give them a reality check and say, ‘This is what you’re facing.’”
Storage
Emnett also called for refinements in the modeling of storage resources. “RTOs generally consider the storage to be operating at full output — full discharge — at the worst time of the system, which generally is not going to be the time that the storage asset is operating that way.”
But he said storage doesn’t need an entirely separate process, either. “Nobody really loves [the current process]. The TOs don’t, the RTOs don’t, the generators don’t. But I’m not sure how you come up with a different one for storage because the question that’s being answered is largely the same: Are you changing the nature of the flows on the system? And what [is] the technical configuration of the equipment that you’re interconnecting and how does that interact with other things?”
Emnett said RTOs should provide more flexibility, praising MISO’s “net zero” policy.
“We’ve put some batteries on existing wind sites that had excess interconnection rights so that interconnection rights had already been studied at a certain level but they weren’t being fully utilized. In our mind, why can’t you just stick another resource on? You don’t have to go through the full study because all you’re using is something you’ve already got.”
He also cited PJM policy allowing interconnection customers to install more capacity than it has in injection rights. The interconnection service agreement requires that the customer limit its output. “If you burn down my wires you are responsible for everything,” Emnett said, summarizing.
Even if it requires a special protection scheme, Emnett said, “it’s going to be, in all likelihood, less expensive than upgrades and able to be implemented much more timely than the two and a half years to get a 10-MW storage project” approved.
The panel also discussed whether the commission should order more standardization in the grid operators’ interconnection processes.
“I hope FERC will allow regional differences,” said panelist Tim Aliff, MISO’s director of reliability planning. He noted the RTO operates in 13 states. “So we have 13 different opinions of how things should be done.”
Aliff also responded to Invenergy’s description of interconnection timelines. “I do take exception to the [assertion that MISO takes] ‘no less than three years’ because it depends on where you are in our footprint,” he said.
In March, FERC rejected the RTO’s proposed changes to its queue process, saying they assumed the current backlog could be blamed on “speculative” projects and “fail[ed] to consider other potential factors” (ER16-675). The commission also said a proposed milestone payment could create barriers to entry for smaller developers. (See MISO Queue Changes on Hold Pending Technical Conference.)
Aliff said that in addition to working on revisions to its proposal, MISO is considering how it can accommodate additional wind growth.
In 2011, MISO approved multi-value projects (MVPs) designed to serve 26 GW of wind. The RTO has 15 GW of installed wind and another 10 GW in the queue.
“So if all of this generation were to interconnect and actually start generating, then we would be at the capacity or close to the capacity of our MVPs,” he said. “So now we’re kicking off the process to say what’s the next step in this? We may or may not come out with MVP-like projects, but we want to get ahead of [the demand] again. We want to look at what the Clean Power Plan is going to do.”
Del Mar became the second city in San Diego County — after San Diego — to announce an objective of moving to 100% renewable energy by 2035. That goal is part of a larger climate action plan to reduce the city’s greenhouse gas emissions.
The oceanfront city hopes to encourage regional utility San Diego Gas and Electric to fully switch to renewable energy by that year, but it is also considering working with neighboring towns to create a community choice aggregator that would serve residents who opt to switch electricity providers.
Owners of gas-fired power plants are warning that they will be forced to shut down their units if the state doesn’t support their need for long-term contracts to maintain operations.
The plant owners argue their units are needed to ensure reliability on a grid that is increasingly subject to intermittent output from cheaper renewables.
A glut of natural gas and a boom in solar has driven wholesale power prices to unexpectedly low levels, threatening the viability of relatively modern gas-fired facilities.
In the latest chapter in their ongoing dispute, the City of Boulder and Xcel Energy are discussing a possible settlement that would end the city’s push to form a municipal electric utility.
The city’s bid to municipalize has not ended just yet, however. Boulder will continue to work on its application to the state Public Utilities Commission to acquire certain Xcel facilities and create its own utility, while also engaging in settlement talks with Xcel. A proposed settlement could come before the City Council this summer, and a new franchise agreement requiring voter approval could be placed on the November ballot.
To date, the city has spent more than $10.4 million on its municipalization bid, about $8 million of which came from the Utility Occupation Tax approved by voters in 2011, which generates about $1.9 million in revenue a year.
The $12 billion merger between Southern Co. and AGL Resources, which would create the second largest utility in the U.S. by customer count, has cleared another hurdle, receiving approval from the Commerce Commission
AGL is the parent company of Nicor Gas, which has 2.2 million customers in the state. The companies expect to complete the merger by the end of the year.
Company Challenges Archeologist over Burial Ground
Doershuk
Energy Transfer Partners says State Archeologist John Doershuk overstepped his bounds by recommending the company reroute its Dakota Access Pipeline to avoid land that Native Americans say is a sacred burial ground.
ETP said that a 2004 survey of the same land by the same archeologist “cleared the property we are crossing of any historic archeological sites.” It said Doershuk’s jurisdiction is over human remains only if they are 150 years old or older, and even then, he can only oversee their relocation and handling.
The Utilities Board granted permission for construction to start where the company already has landowners’ permission, but the state Department of Natural Resources issued a stop-work order based on Doershuk’s findings.
A coalition of business owners and nonprofit groups are urging the Public Utilities Commission to take a slower approach to major changes in net metering compensation to solar power owners.
In April, the Legislature narrowly defeated a bill that would have changed how behind-the-meter solar is credited, which put the issue in front of regulators.
More than two dozen businesses and environmental groups sent a petition Thursday requesting that the PUC give lawmakers and stakeholders more time to continue working on the issue in order to make sure that changes do not affect existing net metering customers and destabilize the rooftop solar industry.
The staff of the Public Service Commission is advising against a microgrid pilot plan by Baltimore Gas and Electric.
BGE has applied to build two public-purpose microgrids, each with a capacity of 2 to 3 MW. It would recover the $16.2 million cost through a customer charge.
The PSC staff questioned the legality of utility-owned microgrids and is asking the commission to take a larger look at the state’s microgrid policies.
The House of Representatives approved legislation that would require utilities to solicit long-term contracts for 1.2 GW each of Canadian hydroelectricity and offshore wind.
Supporters say the measure is a critical step in reducing greenhouse gas emissions and replacing energy that has left or will be leaving the New England energy grid in the coming years, including the scheduled 2019 shutdown of the Pilgrim nuclear power plant in Plymouth.
Some environmental activists say the House bill doesn’t go far enough in promoting renewable energy, while power generators say it interferes with the development of energy markets. (See Massachusetts Clean Power Bill Hit from All Sides.)
Battle Creek police arrested Joshua Buchanan on Thursday in connection to a firebomb found by workers at a Consumers Energy substation the day before.
Police did not provide any other information about Buchanan or the arrest. The Battle Creek Bomb Squad spent several hours at the substation removing a “crude incendiary device” and two gasoline cans. Sgt. Troy Gilleylen said the potential explosive device was not very sophisticated. The FBI is assisting in the investigation, and Buchanan could face terrorism charges.
“If this was put together properly it could have caused a lot of issues,” Gilleylen said. “These items were found inside a fenced area and under some heavy electrical equipment that routes power through Battle Creek.”
The Public Service Commission has fined Consumers Energy $515,800 over failing to provide thousands of its ratepayers with accurate meter readings.
Regulators announced the fine after an investigation into the company’s practice revealed the utility was violating rules for estimated billing. The PSC said Consumers lacked efficient monitoring, controls and customer communications.
The PSC said Consumers Energy improperly relied on usage estimates for more than a year for 12,671 customers. The fine represents about $200 for each customer whose usage was estimated in the past 16 months.
Public Service Commission staff have asked the commission to intervene in Great Plains Energy’s acquisition of Westar Energy, citing a 15-year old agreement in which Great Plains agreed to get PSC approval if it wanted to acquire a public utility.
The agreement stems from Great Plains’ purchase of Aquila in 2001. Great Plains countered that the agreement only applies to the purchase of utilities in the state. Westar is based in Kansas.
After utilities made an unsuccessful push to dramatically overhaul the state’s regulatory framework last legislative session, the Public Service Commission is moving to explore a “middle ground” on the way it oversees them.
The commission voted to open a case to bring together utilities, consumer groups and other parties in the hopes of brokering a conversation outside of the legislature. The move comes after the utilities’ failed effort to reduce the PSC’s discretion over setting rates and approving utility expenses.
Electric utilities said they need faster reimbursement to incentivize investment in aging infrastructure, but consumer groups countered the changes are unnecessary.
Coal production in the state declined by nearly a third during the first four months of 2016, with coal companies producing 4 million fewer tons so far this year.
The decline in demand was caused by the mild winter weather and utilities switching fuel sources, said Bud Clinch of the Montana Coal Council. Lower sales volume and lower coal prices may reduce tax revenues by as much as $25 million, he said.
A Nebraska wind-energy producer has asked state courts to force three public power entities to disclose their generation costs.
Aksamit Resource Management filed the action in three counties where it is building wind projects. Ratepayers “should know the costs and revenues associated with their publicly owned and operated public power districts,” CEO Gary Aksamit said. “When we get this information, we plan to share it with all Nebraskans so they can better understand why their electric rates have increased so much in recent years.”
The Nebraska Public Power District and the Omaha Public Power District say the information amounts to trade secrets and may be kept confidential, while the Municipal Energy Agency of Nebraska says it has provided sufficient information already.
The Antelope County Board of Supervisors approved a plan by Invenergy to erect 160 wind turbines. The supervisors imposed several conditions on the project, such as increased setback distances and completion of a noise analysis within 24 months after the structures are erected.
Eight turbines in the original proposal were dropped because of potential conflict with flight space around the Neligh airport.
A local protest group has re-formed to oppose Jersey Central Power & Light’s proposal to build a $75 million transmission line between Aberdeen and Red Bank. The same group successfully fought the same transmission line project in the 1990s.
Residents Against Giant Electric said it is concerned about the proposal’s effect on property values, health risks and aesthetics.
JCP&L’s Monmouth County Reliability Project consists of a 230-kV line that would run 10 miles along a commuter railroad.
The state Court of Appeals has ordered the Utilities Commission to revisit its decision to require environmental activists to pay a multimillion-dollar bond in order to appeal the commission’s approval of a Duke Energy power plant near Asheville.
The commission will hold a hearing on June 17 to reconsider its decision to require activist groups NC WARN and The Climate Times to put up a $10 million bond to pay for the cost of potential delays to the $1.1 billion project should their appeal be unsuccessful. Duke had asked for the bond amount to be set at $50 million.
The activists argued that requiring such a high bond was, in effect, blocking them from access to the appeal process.
The Public Service Commission spent 10 hours last week listening to testimony and comments regarding NextEra Energy’s proposed 72-turbine, 150-MW Brady Wind Energy Center II.
If approved, the $250 million project in Hettinger County will adjoin the proposed 87-turbine Brady Wind I wind farm in neighboring Stark County to the north. Brady Wind I and Brady Wind II could be online as soon as December, NextEra said.
If construction is not finished by December and the turbines aren’t operational, NextEra will be fined by Basin Electric Power Cooperative for not fulfilling its end of a power purchase agreement.
The nominating council for the Public Utilities Commission has selected nine candidates from the 19 who applied for the vacancy left by outgoing Chairman Andre Porter.
The council selected Edward Hess, Dave Hall, M. Howard Petricoff, Sam Gerhardstein, Lawrence Friedman, James Teitt, Andrew Thomas, Mark Ward and Gregory Williams for consideration. The council will interview the candidates on June 16.
The names of four finalists will then be forwarded to Gov. John Kasich for the final decision. Sierra Club activist Daniel Sawmiller, who led the opposition against FirstEnergy’s proposed power purchase agreements, did not make the cut.
A state task force is likely to recommend ways that legalized indoor marijuana growers can economize on their intensive use of energy and water rather than impose any limits on the booming horticultural business.
The panel is set to report to the legislature later this summer, likely proposing a new certification process that would encourage growers to conserve resources and suggest ways the state can provide education on the subject. Energy experts are concerned the growing demand from pot growers will require adjustments in the power grid.
The new industry, which became legal in October, is interested in energy efficiency but says best practices have not been established and information is not widely available.
Daniel J. Mumford, who spent 26 years with the Public Utility Commission’s Bureau of Consumer Services, has been appointed director of the Office of Competitive Market Oversight. Mumford most recently helped direct the commission’s investigations into the state’s retail electric and natural gas markets and formulate changes in the wake of the polar vortex of 2014.
“Those regulatory changes served consumers well by enhancing supplier disclosure requirements, strengthening consumer protections and reducing the time needed to switch suppliers,” PUC Chair Gladys M. Brown said. “As Pennsylvania’s markets continue to evolve, we are pleased to have Dan at the helm leading OCMO.”
Megan G. Good, an analyst with the PUC’s Bureau of Technical Utility Services, will become the OCMO deputy director.
The House of Representatives voted 64-7 to approve a bill intended to block a $700 million natural gas-fired power plant proposed in Burrillville.
The bill would require any tax agreement that the Burrillville Town Council reaches with developer Invenergy to be voted on in a town-wide referendum. Invenergy and its supporters, which include construction unions and business groups, say the legislation could lead to similar efforts to block infrastructure projects in other communities.
About half of the plant’s 900-MW capacity was successfully bid into the ISO-NE’s Forward Capacity Auction for delivery year 2019/20.
Prices in Deregulated Markets Still Higher than Regulated
Consumers shopping for electricity in the state’s deregulated market in 2014 paid more on average than those without choices, though the price disadvantage was smaller than in years past, according to a new study.
Residential power prices in deregulated markets, which cover about 85% of Texas, averaged 15.5% higher than those in regulated areas, where consumers cannot choose their providers. But the difference between the two markets has been shrinking in recent years. Statewide, power prices are below the national average.
The study was conducted by the Texas Coalition for Affordable Power, which advocates for cities and other local governments and negotiates their power contracts. It analyzed federal data on residential prices stretching back to 2002, the first year most of the state was deregulated.
State Expecting ‘Bumper Crop’ of Solar Farms this Summer
At least 20 “community solar” farms are scheduled to either be built or come online this summer in the state, according to industry insiders at last week’s Solar Power Southwest Conference.
The state is expected to have 14 GW of solar projects on the grid, but most of the focus has been on utility-scale and rooftop projects. Under community solar programs, homeowners in single-family dwellings can purchase individual solar panels on a farm and receive credits on their monthly light bills based on production.
Advocates say that community solar fills in the gaps by allowing renters and those homeowners restricted by covenants or with large shade trees on their property to purchase panels at these off-site, third-party solar farms to take advantage of those credits.
FAA Signs off on 86-Turbine Wind Farm in Chapman Ranch
The Federal Aviation Administration ruled that 86 wind turbines planned for Chapman Ranch, near Corpus Christi, won’t be hazardous for air navigation, clearing a significant hurdle for the proposed wind farm’s developer, Apex Clean Energy.
The agency conducted separate studies for each individual wind turbine that evaluated the structure and its impact on air traffic. Analysts concluded that each would present no hazard to air navigation, provided that the wind turbines have markings and lighting as stipulated.
The Corpus Christi City Council adopted a resolution in 2014 opposing the proposed wind farm. That position hasn’t changed, said Tom Tagliabue, the city’s director of intergovernmental relations. The council voted later that year to annex 16 square miles of Chapman Ranch in hopes that it would halt the project, but Apex said the turbines are not planned for construction in the city-annexed land.
Gov. Peter Shumlin vetoed a bill giving communities more say in the siting of wind and solar power projects.
Shumlin said he supported the parts of the bill giving towns and regional planning commissions more input in the siting of energy projects, but he objected to the tighter standards for noise from wind turbines. The standards effectively would “make Vermont the first state in the country to declare a public health emergency around wind energy, without peer-reviewed science backing that assertion up,” the governor said in his veto message.
The governor’s other objections included language on solar energy that he said could create a problem with deeds when properties are sold, and a lack of funding for regional planning commissions to do new energy planning work.
DEQ Issues Permits for Dominion’s Ash Pond Draining
The Department of Environmental Quality issued a draft of a permit that would allow Dominion Virginia Power to drain up to 5 million gallons of coal ash pond water a day into the James River. The permit is one of four the company will need to begin draining the impoundment at Chesterfield Power Station.
The company is under federal mandate to drain the ash ponds at Chesterfield and Bremo Bluff Power station. Environmental groups won a legal challenge to the company’s first efforts at Bremo, and they vow to study the permit to make sure it meets the necessary standards.
The state will accept written comments about the permit through July 21.
Foes of the proposed Atlantic Coast and Mountain Valley pipelines, assisted by veterans from the anti-Keystone XL Pipeline effort, planted corn in the paths of the two projects in Franklin. They hope the “Seeds of Protest” will grow into a symbolic barricade of the shale-gas pipelines.
“I have children and grandchildren and I want them to grow up in a world with clean water, clean air and healthy food to eat,” said Mekasi Horinek Camp, a member of the Ponca Tribe, who joined in the protest. “Anything that threatens Mother Earth threatens my children and grandchildren.”
The Madison City Council adopted a measure last week to cut the city’s emissions 80% by 2050.
The plan creates an inventory of city-owned property that could house rooftop solar and establishes the Property Assessed Clean Energy (PACE) program to assist property owners in financing energy upgrades. The city has also committed to creating permanent energy staff positions and reviewing its climate change plan.
The plan also recommends the city obtain a quarter of its electricity from clean sources by 2025 and half by 2030.
Solar advocates have asked legislators to back a proposal lifting the 25-kW cap on solar installations eligible to sell surplus power back into the grid, expanding the practice of net metering to larger projects. Supporters hope the measure will boost commercial solar installations and create jobs as the state confronts the declining fortunes of its oil, gas and coal industries.
The measure is expected to meet opposition from utilities, including PacifiCorp, which last month told state lawmakers the practice amounted to paying subsidies to homes and businesses with solar panels.
Beginning this year, Capacity Performance units no longer would be compensated for participating in cold weather testing, which is set to be continued under a plan that the PJM Operating Committee will be asked to endorse in August.
The program is voluntary, noted PJM’s David Schweizer, and generators may self-schedule their own testing.
As PJM moves to a Capacity Performance model, designed to avoid the outages experienced during the Polar Vortex, the RTO wants to continue winter testing but end generator compensation.
The rationale behind the change, which was first mentioned in April, is that PJM expects generators to factor the cost of testing into their offers. (See “Plan: Continue Cold Weather Testing, End Compensation for CP Participants,” PJM Operating Committee Briefs.)
All units will be required to be Capacity Performance beginning in the 2020/21 delivery year.
There were no other changes recommended for the program, which Schweizer said was valuable even though it didn’t yield much useful data last winter because of warmer temperatures.
Several members representing generation said the testing program will be a tough sell absent compensation.
“Without compensation, the program will dry up,” said one stakeholder who asked not to be identified.
John Farber of the Delaware Public Service Commission supported the plan.
“Customers are paying for premium capacity. The question is if they’re getting it,” he said. “We support where PJM is going with this. We really think compensation should be covered through the CP offer.”
Committee Chair Mike Bryson said staff would incorporate members’ comments into revised manual language that will be brought to a first read in July.
PJM Won’t Ask FERC to Rehear Ramp Rate Proposal, Plans to Collect Data
The Tariff changes would have exempted a capacity resource from nonperformance charges if it was following PJM’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. They were drafted as a temporary measure to guard against generators self-scheduling prior to a PAH.
“As of right now, it’s status quo,” said PJM’s Rebecca Stadelmeyer, who convened a number of lengthy discussions over the past few months to win stakeholder consensus. “You need to be at expected Capacity Performance immediately.”
“We have decided internally that we’re not going to request a rehearing, largely because we took a good look at the arguments using examples we had from stakeholder endorsement,” Bryson said. “I think data is the next cog in getting this done. We’ll continue to collect that. I don’t know if we necessarily need an emergency situation to get all the data, though a performance assessment hour would help.”
Stu Bresler, senior vice president for operation and markets, agreed.
“We were disappointed that FERC didn’t take our word for it, but it seems the only thing that will change their minds at this point is data,” he said.
GOs to be Questioned on Governor Response Survey Results
PJM is concerned that most units participating in PJM’s Governor Response Survey did not provide reasons for deviating from NERC settings.
Schweizer said staff would be reaching out to generation operators to better understand the survey results, including why 5% of units didn’t participate.
Of those responding, 76% reported they had a governor capable of changing output in response to changes in interconnection frequency; 69% said their governor was operational; and 53% responded that their governor was capable of operating with the settings recommended by NERC.
About 43% of combustion turbines, 29% of combined cycle units and 24% of steam/fossil units reported they were capable of providing frequency response in accordance with NERC guidelines. Only 8% of hydro units and 1% of nuclear units reported such capability.
Two-thirds of the units did not provide a reason for deviation from NERC settings.
Among the reasons reported: control mode does not allow (10%); did not align with NERC-recommended dead-band (9%); and set with a slightly less droop setting of 4% (5%).
WASHINGTON — Four Ph.Ds. joined in a tag-team debate last week on the virtues of scarcity pricing versus capacity markets in a panel discussion-cum-economics seminar at the Energy Bar Association’s Annual Meeting.
It’s unlikely any of the combatants, who have often sparred each other, came away with any different opinions. But the repartee was no less sharp for the familiarity.
William W. Hogan, research director of the Harvard Electricity Policy Group, staked out the energy market-only pole of the debate, repeating his argument that capacity markets are unnecessary if the energy and ancillary services markets “get their prices right.”
“Life is too short to spend your time trying to perfect capacity markets,” Hogan said.
PJM Market Monitor Joe Bowring said Hogan’s vision is unrealistic. “It’s easy enough to say in a theoretical world that scarcity pricing should take care of everything. But we have yet to see that demonstrated in the real world,” he said.
Administrative Determinations
Bowring also attempted to puncture any notion that scarcity pricing is much simpler than capacity markets.
“Let’s not pretend that scarcity pricing is some automatic market mechanism that will simply take care of problems without an intervention,” he said. “It is equally administrative as capacity markets — just different. You still have to determine … the appropriate net revenue. And it’s a lot trickier than it sounds.”
Sam Newell, a principal with The Brattle Group, challenged Bowring’s assertion.
“Although the pricing in an operating reserve demand curve [ORDC] is administratively determined, actually there’s less administrative determinations than in a capacity market because you’re just saying what the prices should go to under certain real-time operating conditions.”
In a capacity market, he continued, “You have to decide what is the reliability concept you’re meeting. Is it summer peak? … You have to decide how different resources can qualify to meet that and so there’s a lot more administrative determinations.”
David Patton, whose Potomac Economics provides monitoring services in MISO, ISO-NE, NYISO and ERCOT, expressed concern over the volatility of generators’ revenue streams under scarcity pricing.
“Unless you’re willing to price shortages at $200,000/MWh, you’re not going to meet your planning requirements with the energy market alone,” he said.
“Shortage pricing is not like a capacity market where you’re going to get a level of revenue that might fluctuate by 10 to 20% a year. With shortage pricing, you might get 10 years of revenue in one year and then the other nine years the generators are going to think they’re going bankrupt.”
This is because shortage prices “increase exponentially when you get unusually hot weather and unusually high loads or unusually poor generator performance,” Patton said. “Look at ERCOT in 2011 and compare the number of shortage incidents you had in that year to the prior 20 years.”
That could lead to constant tinkering, Patton said. “You don’t want policymakers to jump in when it’s not producing revenues for a number of years. You also don’t want them to jump in in the year when it produces $20 billion of revenue,” he said. “Because that’s what you signed up for.”
Bowring added another potential negative consequence.
“What will happen if you go through eight years of very low revenues under scarcity pricing … and a significant number of units decide to retire because they can’t see into the future? They don’t know if [in] the ninth or 10th year there’s going to be $20 billion. They retire if the revenues aren’t adequate.
“There’s a level of risk associated with scarcity pricing that differs from capacity markets, which is why the optimum might be to have more revenues in the scarcity pricing but not 100% of expected revenues,” Bowring said.
Locational Issues
Bowring said he agreed with the need for scarcity pricing but said it “is done very ineffectively now” in PJM because the ORDC hasn’t been made “adequately locational.”
“Scarcity doesn’t work if it’s an aggregate, because you can be long aggregate in PJM or other big RTOs or ISOs and be very short in particular places,” he said.
Joint Optimization
ERCOT has a different problem, said Patton: a failure to jointly optimize the energy and shortage markets so that the ISO can price transitory shortages.
“We perpetually undercompensate units like pump storage units, combined cycle units. They’re way more valuable for reliability because they can ramp fast,” he said. “But if you don’t reveal the true state of the system in every five minutes you undercompensate them.”
Hogan sought to allay what he called a misconception that shortage pricing is incompatible with price caps and other market mitigation measures.
“The advantage of this operating reserve demand curve … is that prices go up because of the scarcity of reserves. They don’t go up necessarily because of high offers by the generators. So it is completely compatible to have offer caps — which are dealing with market power problems with generators — that are set by their variable cost of operation. You could have a $500 offer cap, say, on generators and then you have the operating reserve demand curve that is setting the price and the price is $3,000/MWh.
“All of the market mitigation … continue to exist. You don’t have to get rid of that,” he continued. “If you don’t have the operating reserve demand curve, offer caps depress the price and do all kinds of bad things.”
Changing Conditions
Newell said scarcity pricing may be better suited to respond to changes facing the industry.
“With variable energy resources suppressing energy prices — creating over-generation sometimes on the one hand, ramping shortages on the other — the nature of reliability is changing, and it’s not just about summer peak.
“And that is another reason why I want to second what Dr. Hogan said. It is better to get the prices right — reflecting real-time conditions and telling the market what you need, when you need it — rather than just having a narrow administrative idea of reliability. So I would like to see more money moving into the energy and ancillary services markets and out of the capacity markets.”
Planners are sticking with their decision to recommend that the PJM Board of Managers approve a $340.6 million market efficiency project to address congestion at the AP South interface.
Since last month, when PJM told the Transmission Expansion Advisory Committee of its intention to back the proposal, planners have conducted additional sensitivity studies on the selected project using lower gas prices. They did not perform additional studies on three competing proposals. (See “Planners Choose Project to Relieve APSouth Congestion,” PJM Planning Committee and TEAC Briefs.)
Project 9A (without capacitors), submitted by Dominion High Voltage and Transource Energy, performed even better at providing production cost savings with low gas inputs, PJM said.
LS Power’s Sharon Segner continued to object to the project being chosen without further study of the three cheaper competing proposals. They ranged from $72 million to $253 million.
For one thing, she said, there was no carbon pricing in the model, so the project is being approved as if the Clean Power Plan, currently stayed by the Supreme Court, will not be implemented.
“Basically, you’re approving the project based on a zero-carbon pricing model in the non-[Regional Greenhouse Gas Initiative] states,” she said. “If you had carbon pricing in the model, project 9A would look different, and competing projects would be different.”
Given the cost of the project, she added, it should be tied to cost caps.
A letter to the TEAC from LS Power’s Northeast Transmission Development expounded on her concerns. Another letter echoed her complaints regarding the carbon pricing assumptions.
“We’ll take a closer look at the operating agreement,” responded TEAC Chair Paul McGlynn. “We’ve certainly done a lot of studies and sensitivities under a number of variables. We think we are satisfying the requirements of the Operating Agreement.”
The expected in-service date is 2020.
PJM to Open FERC Order 1000 Proposal Window in Late June
PJM expects to open its second 2016 Regional Transmission Expansion Plan window in the last week of June, McGlynn said.
Its scope will consist of a year 2021 analysis of N-1 and N-1-1 thermal and voltage contingencies; generation deliverability and common mode outages; and load deliverability thermal and voltage.
Newark Airport’s Increased Energy Need May Spark Reliability Violation
Newark Liberty International Airport has identified a need for additional energy resources. Its current load is about 40 MVA, but a new planned terminal is expected to increase that load by about 33 MVA.
Meanwhile, the Port Authority of New York and New Jersey’s future plans for its PATH rail line are anticipated to add another 8 MVA for a total of 81 MVA.
The airport’s energy needs are expected to increase further with planned upgrades to Terminal B and Terminal C.
Newark Airport Source: Newark Liberty International Airport
The facility’s load will be served by two new 345-kV underground cable circuits, part of the Bergen-Linden Corridor project. Existing 26-kV circuits will be used for backup.
However, that presents a potential reliability violation, because a portion of the 26-kV station property is owned by the airport, and it has requested the use of the land back. In addition, the 26-kV facilities are aging and potentially thermally overloaded.
Artificial Island Project Alternatives, Cost Continue to be Studied
PJM and Public Service Electric and Gas are continuing to look at ways to reduce the cost of the Artificial Island stability fix, including moving the 230-kV line to Hope Creek instead of the Salem substation.
“Cost estimates are being developed for the new configuration,” McGlynn said. “We are looking at it from a scheduling perspective as well — what potential impact it may have on changing the design of the project. There is also ongoing work relating to analytical work and stability studies.” (See Artificial Island Cost Increase Could Lead to Rebid.)
Installed Reserve Margin Study Assumptions Endorsed
The Planning Committee endorsed the 2016 installed reserve margin (IRM) study assumptions developed by the Resource Adequacy Analysis Subcommittee.
The recommendation retains the current load model selection process with one minor change: clarifying that the annual peak can only be drawn from the summer peak week. (See “IRM Assumptions Presented for First Read,” PJM Planning Committee and TEAC Briefs.)
PJM’s Tom Falin said that had the change been implemented for last year, the same load model would have been selected, and the IRM would have been the same.
Planners also will continue to model a 2.5-GW ambient derating for the summer.
PJM Beefing up Details of TO Upgrade Exemption Proposal
PJM staff is adding more details to its plan to exclude typical transmission substation equipment from competitive windows as a result of questions that FERC had regarding the RTO’s proposal to exclude some low-voltage projects from the process. The commission responded to PJM’s voltage floor proposal with a May 27 deficiency notice ordering the RTO to provide additional information (ER16-1335).
“With this process, it’s going to be similar [to the voltage floor proposal] because we’re basically excluding problems that we think will result in a transmission owner upgrade,” PJM’s Mark Sims said. “If [FERC] had concerns with the voltage floor, they probably would have concerns with this.” (See “Typical TO Upgrades Would be Excluded from Competitive Window under Proposal,” PJM Planning and TEAC Briefs.)
Among FERC’s concerns was how stakeholders could comment on exempted projects. PJM’s Sue Glatz said the RTO is drafting a compliance filing to FERC due at the end of the month regarding the voltage floor exemption.
The PC will be asked to endorse the TO upgrade exemption next month.
80% of Projects Submitted in Past 6 Months Wouldn’t Meet New Procedures
About 80% of the projects submitted to the proposal queue would have been bumped if new submittal procedures had been in place, PJM’s Dave Egan said in his semiannual update of the project queue. (See “Stricter Rules Proposed for Queue Submittal Process,” PJM Planning Committee and TEAC Briefs.)
More than half of the projects for the six-month queue were submitted on the last day, he said.
He noted there has been an uptick in solar projects in Virginia and North Carolina and a slight reduction overall in natural gas.
Task Force Breaks into Subgroups to Study Minimum Design Standards
The Designated Entity Design Senior Task Force, created to draft minimum design requirements for competitively solicited facilities, has divided into three subgroups to focus on transmission lines, substations and system protection, and control design and coordination. (See “Task Force will Create Design Standards for Competitive Projects,” PJM Planning Committee and TEAC Briefs.)
The protection subgroup has determined that Manual M7 is a good starting point but will be examining additional items, including metering requirements, commissioning procedures and disturbance monitoring equipment.
The main focus of the substation subgroup will be different voltages, criteria-based design, functional layout, future expansion and minimum outages.
The task force expects to deliver its recommendations to the PC in September.
Network Upgrade Cost Allocation Process Hits a Snag
PJM is studying issues it has identified with the network upgrade cost allocation process for new service queue requests.
PJM’s Aaron Berner explained that in studying the need for projects, customers are evaluated together. But when it comes to allocating the cost of approved projects, transmission service customers aren’t allowed to share costs with the other customers.
“Everybody is studied together. Then we come to the point in the Tariff that discusses cost allocation as opposed to mechanics. We then cannot allocate cost to transmission service customers,” he said.
He expects to return next month with a draft problem statement to address the issue.
Plant retirements could cause a generation shortfall in MISO as early as 2018, two years earlier than previously expected, according to the RTO’s 2016 survey with the Organization of MISO States.
The survey, released Friday by MISO and OMS, forecasts a narrow surplus in 2017 but concludes that “action is required in the near term to ensure sufficient resources in future years.”
For 2017, MISO is forecast to exceed the projected 15.2% reserve requirement by 0.9 GW (0.7% above the requirement), although multiple zones will be below their resource requirement and will have to rely on imports. Southern Illinois’ Zone 4 could have a 0.5-GW surplus or a deficit as large as 1.2 GW. Zone 5 in Missouri is forecasted to have a 0.8-GW deficit, and Zone 7 in Lower Michigan could have 0.3-GW shortfall.
By 2018, the survey says, MISO will face a 0.4-GW shortfall if no “low certainty” generation — projects in the interconnection queue that have not signed interconnection agreements — are completed. Under the same worst-case scenario, the gap rises to 0.5 GW in 2019, 1.9 GW in 2020 and 2.6 GW in 2021.
Half of MISO zones are predicted to experience a shortfall by 2021, with only the Dakotas (Zone 1), Wisconsin and Upper Michigan (Zone 2) and MISO South (zones 8, 9 and 10) showing sufficient capacity. Zone 4 could have the largest shortage at 1.7 GW.
Under a best-case scenario that assumes all low-certainty resources go into commercial operation, the 15.2% planning reserve margin could be met throughout 2018-2021, reaching 16.9% in 2018, 17.1% in 2019, 16.1% in 2020 and 15.5% in 2021.
Worsening Forecast
Last year’s survey predicted a 2.6-GW regional surplus in 2017, a 1.7- to 2.3-GW regional surplus in 2016 and a deficit by 2020. (See MISO Survey: No Shortfall Until 2020.)
Jennifer Curran, MISO vice president of system planning and seams administration, said the worsening forecast resulted solely from increased retirements, including those in Southern Illinois. (See Dynegy to Shutter 3 Ill. Coal Plants; Blames MISO Market Design.) The new survey appeared to be on track with last year’s forecast, pegging the 2017 regional surplus at 2.7 GW, but calculations were adjusted to reflect recently announced retirements.
According to MISO staff, the survey took into account all recently announced retirements, including DTE Energy’s planned retirement of eight coal-fired units in Michigan beginning in 2020 and the 2017 closure of Exelon’s Clinton Nuclear Generating Station in Illinois. For the first time, the survey included merchant generators in addition to load-serving entities.
Time to Get to Work
During a Friday conference call, both Curran and Sally Talberg, OMS president and chair of the Michigan Public Service Commission, stressed that state officials and regulators and load-serving entities should be working on resource adequacy plans.
“I would note that the load-serving entities in Zone 4 can take action any time using bilateral contracts,” said Curran, who also noted MISO’s plan to change the capacity auction design for the zone. (See MISO Moves Forward on Auction Design; Seasonal Filing Delayed Again.)
“This is a crucial period given the amount of resources that have retired and will retire during the survey horizon,” Talberg said.
MISO CEO John Bear said the RTO will continue to support “state regulators and members as they take necessary actions to ensure continued resource adequacy in 2018 and beyond.”
Curran said MISO’s flood of retirements is partially offset by lower demand, but that retirements are still outpacing new resource additions. She said while the number of projects in the generator interconnection queue has increased, the number of projects that complete the process and begin producing power “has remained flat.” For 2017, the survey predicted 0.7 GW of high-certainty new resource additions.
“Firming up those planned generation interconnections is going to be important,” Curran added.
In 2017, the survey shows zonal transfer limitations keep some projected capacity from serving load elsewhere. Curran said the constraints in Zone 1 are being addressed with transmission construction and that MISO is in talks to identify a solution to the transfer limits between the North and South regions.
Disparity
During the conference call, multiple stakeholders questioned the survey’s forecast, asking why the capacity auction results showed a larger surplus than the survey results for the second year in a row. (See MISO’s 4th Capacity Auction Results in Disparity.)
“It’s a survey and we have made certain assumptions,” Curran responded. “This is a reflection of 2017, not the current year auction results.” She said the survey is not the “end-all, be-all” in future capacity.
MISO plans to hold a detailed breakdown of survey results at the June 29 Resource Adequacy Subcommittee meeting.
ERCOT’s Independent Market Monitor said the market “performed competitively” in 2015, with low natural gas prices helping reduce energy costs and congestion revenue to record lows.
Potomac Economics’ annual State of the Market report, filed with ERCOT and the Public Utility Commission of Texas, said the ISO’s average real-time energy price fell 34% last year to $26.77/MWh, eclipsing 2012’s prices ($28.33/MWh) as the lowest annual energy cost since the nodal market came online in December 2010.
The drop was fueled by average natural gas prices 41% lower in 2015 than 2014, falling from $4.32/MMBtu to $2.57/MMBtu. The Monitor said the correlation between gas prices and energy costs is to be expected in a “well-functioning, competitive market,” as “fuel costs represent the majority of most suppliers’ marginal production costs.”
“Suppliers in a competitive market have an incentive to offer supply at marginal costs and natural gas is the most widely used fuel in ERCOT,” the Monitor said.
Lower gas prices also contributed to a $352 million decrease in congestion revenue, down 50% from 2014’s record $704 million, despite a similar number of binding constraints as the year before. The total was more than $100 million lower than the previous low for congestion costs.
“This is largely due [to] the significant reduction in natural gas prices and the cumulative benefits of large investments in transmission facilities,” the Monitor said, noting gas units are typically re-dispatched to manage system flows.
The report also indicates ERCOT’s average real-time load was up 2.4% from 2014 — the ISO set a new hourly demand record of 69,877 MW on Aug. 10 — but that shortages were “rare” and planning reserves were above the minimum requirement. However, the Monitor said the market’s net revenues were less than the amount needed to support construction of new gas units. It calculated net revenue for new gas turbines last year at $23 to $29/kW-year, far below the necessary $80 to $95/kW-year.
The Monitor found both nuclear and coal units to be money losers in 2015. The ISO’s four nuclear units’ generation-weighted average price was $24.56/MWh in 2015, compared to the Nuclear Energy Institute’s estimated operating costs of $27.53/MWh last year. Coal and lignite units averaged $25.94/MWh prices, compared with the Monitor’s assumed fuel-only operating costs of approximately $30/MWh.
“This is significant because the retirement or suspended operation of some of these units could cause ERCOT’s capacity margin to fall below the minimum target more quickly than anticipated,” the Monitor said. It currently predicts ERCOT’s reserve margin will stay above its 13.75% target “for the next several years.”
The Monitor acknowledged ERCOT made several improvements to its market in 2015 in response to its recommendations, but it said three suggestions from last year have yet to be addressed. It recommends ERCOT:
Implement real-time co-optimization of energy and ancillary services;
Modify the real-time market software to better commit load and generation resources that can be online within 30 minutes; and
Price future ancillary services based on the shadow price — the system cost for the last megawatt of load — of procuring the service.
The Monitor also said the PUC should evaluate policies that create incentives for loads to reduce consumption for reasons unrelated to real-time energy prices, including the need for emergency response service (ERS) and the allocation of transmission costs. It said the “lucrative” ERS program limits the motivation for loads to participate and contribute to load formation in the real-time market, while rising transmission costs “significantly” increase the already substantial incentive to reduce load during the summer season’s probable peak intervals.
“Both of these mechanisms provide strong incentives for load to act in ways that are not aligned with the most efficient electricity market outcomes,” the Monitor said, “which are to ensure that the price continually reflects both the cost to provide (supply) and the value to consume (demand).”
Constitution Pipeline asked FERC on Thursday to dismiss a complaint by New York’s attorney general alleging illegal tree cutting, requesting fast-track resolution to the ongoing dispute over the proposed 124-mile natural gas project (CP13-499).
The company vehemently denied allegations made by Attorney General Eric Schneiderman that it encouraged illegal tree cutting by landowners in defiance of a FERC prohibition, calling the complaint “part of a pattern seeking to delay construction.”
“The complaint does not contain any evidence that ‘clear-cutting’ … has occurred or, if it did occur, that it was performed or caused by Constitution,” the company wrote. “Instead, the complaint merely contains vague allegations that landowners or the landowners’ logging companies, against whom the attorney general seeks no enforcement action, conducted tree clearing, road building or other ground disturbing activity on the pipeline right of way in New York, in 10 locations [that] the attorney general refuses to, and fails to, describe with any specificity sufficient to actually identify any of them.”
Constitution said the vagueness of the attorney general’s complaint required that FERC appoint an administrative law judge to develop a complete record. It also said that fast-track processing was necessary because the complaint alleged ongoing violations of federal law.
The pipeline is intended to bring shale gas from the Marcellus region of Pennsylvania into the New York and New England markets.
In April, the New York Department of Environmental Conservation denied Constitution a water quality permit under Section 401 of the federal Clean Water Act. Constitution last month appealed the permit denial in federal court. (See Constitution Pipeline Appeals Rejection of Water Permit.)
MISO said last week it will not yield on a planned July filing for capacity auction changes in deregulated areas, but a filing to add seasonal and locational constructs will be delayed until later this year.
During a two-day meeting of the Resource Adequacy Subcommittee, Jeff Bladen, executive director of MISO market services, said the July 15 filing goal for a new auction design is unchanged and draft Tariff language will be in front of stakeholders in time for a special meeting of the RASC on June 13.
The Tariff filing planned for next month would introduce a bifurcated procurement using both the existing Planning Reserve Auction and a separate three-year forward model for deregulated areas that would use a sloped demand curve. MISO will allow regulated demand to voluntarily participate in the forward auction, but not regulated supply.
The RTO released business rules and an updated work plan on its proposal and has retained The Brattle Group to review it.
Bladen also addressed disagreements between MISO and the Independent Market Monitor over the proposed changes, saying the RTO was working to “close the gap.”
“I wouldn’t describe it as ‘at odds,’” Bladen said of the opposing viewpoints. “There’s a philosophical difference in how a sloping demand curve would be applied. We’re trying not to place any new rules on nonparticipating states.”
“This isn’t a summit meeting of Cold War adversaries,” Bladen reassured stakeholders. “MISO meets with the IMM regularly, and there are discussions between MISO and [Monitor David] Patton and his staff almost every day.”
Bladen conceded that if the talks result in major changes to the design construct, the July filing timeline would be “very hard” to accomplish.
Bill Booth of the Mississippi Public Service Commission asked what changes might result from the talks.
“I certainly wish I had an answer on what a compromise is going to look like, but we’re going to work through it … and find common ground,” Bladen said.
Other stakeholders repeated a desire for more time to review simulation results and vet Tariff language.
“We understand where your intentions are, but there are some that think the competitive retail solution isn’t necessary, and there’s a lot of work to be done in the Business Practice Manuals. I think the July Tariff filing is overly ambitious,” said Jim Dauphinais, counsel for Illinois Industrial Energy Consumers.
NRG Energy’s Tia Elliott asked if MISO would have a third party critique the Monitor’s proposed solution as well as the RTO’s. Bladen said that could be done.
MISO released 17 pages of business rules last week based on the prior presentations and asked for stakeholder response by June 8 so input could shape draft Tariff language, which is due in time for the June 13 special meeting of the RASC. Subcommittee liaison Renuka Chatterjee said the rules could be made into a new Business Practices Manual or inserted into existing BPM 11, which governs the Planning Resource Auction (PRA).
“This is very much a first draft,” Dauphinais said of the business rules document, pointing out that a demand curve shape hasn’t yet been settled on. “We’re concerned you’re not prepared to put out Tariff language on June 8.”
“I’ve heard a lot of opposition, but I haven’t heard a lot of support,” added Booth.
“Nothing is ever not contested at FERC,” Chatterjee offered in response.
A filing to implement external resource zones in addition to MISO’s existing local resource zones (pictured above) and a two-season capacity construct will be delayed until the fall as the RTO gathers more information from stakeholders.
Chatterjee outlined the work plan:
June-July: Rewrite Tariff and BPM language
July-January: Software development
October-February: Internal and external auction training
March: Launch (for 2017/18 planning year)
Study to Delay Seasonal, Locational Construct
While pushing ahead on the auction design, MISO has abandoned the July filing goal of seasonal and locational constructs and promised stakeholders an additional two months for the concepts to be vetted through the RASC. The delay will allow completion of a new seasonal loss-of-load expectation (LOLE) study and continuing talks on dividing capacity accreditation into winter and summer, according to MISO’s Laura Rauch.
The study will explore how lower capacity reserve margins in the winter would affect seasonal capacity accreditation and how separate summer and winter LOLEs would impact capacity import/export limits and planning reserve margins. Rauch said MISO does not expect to have specific numbers on transfer capabilities and seasonal reserve margins until the fall.
Rauch also said more time is needed to consider definitions of external resource zones.
“We don’t want to put a hard and fast timeline on this. Once we resolved these concerns, we will file, but we do want to file this year,” Rauch said. Pressed by stakeholders, she said MISO is envisioning a September filing but would make an October filing if discussion or study findings warranted postponement.
“We’ve had three filings dates out there, and we don’t want to keep moving things around,” Chatterjee added.
Rauch said an open question is how MISO should define forced outage rates and planned outage hours during critical hours: weekday hours ending 15, 16 and 17 during June, July and August; and weekday hours ending 9, 19 and 20 during December, January and February.
Rauch said a seasonal capacity accreditation process would begin next June.
Even with the seasonal and locational constructs paused for discussion, stakeholders were wary.
“I get the impression MISO just wants time to explain this better, but there’s opposition because other alternatives exist,” Customized Energy Solutions’ David Sapper said.
Dynegy’s Mark Volpe also said stakeholders don’t want to spend the next two months sounding like a “broken record” on recommendations.
Both Chatterjee and Rauch said MISO staff would take time to respond to new questions and recommendations in the coming weeks.
Monitor Outlines Approach on Avoidable Costs
Meanwhile, Market Monitor Michael Chiasson outlined an approach that relies heavily on PJM to develop default technology-specific avoidable costs for future PRAs. FERC mandated the defaults in its New Year’s Eve order to lessen the burden of verifying reference levels on a unit-by-unit basis (EL15-70et al.).
MISO and the Monitor agree that the RTO should use PJM default values for the 2017/18 planning year but without PJM’s 10% adder. Chiasson said MISO doesn’t have enough time to survey generators to develop its own default values before next year’s auction.
“The June 28 compliance filing deadline makes it unlikely that a MISO survey would receive a sufficient number of responses to produce representative results for the various technology types,” the Monitor explained. However, the Monitor said it would “consider expanding the IMM’s operating cost survey so the default values can be based on MISO participant data in future years.”
Because PJM doesn’t develop default values for nuclear and wind units, the Monitor is proposing a wind avoidable cost of $108.30/MW-day based on Energy Information Administration data and a nuclear avoidable cost of $454.79/MW-day based on a recent white paper by the Nuclear Energy Institute.
For all the avoidable cost values, the Monitor suggested using the monthly Consumer Price Index to update values. Chiasson said the Monitor considered using other indices that track power production costs, but they were either overly reliant on capital costs versus operations and maintenance expenses, their values were too volatile or the reports weren’t produced often enough. For planning years beginning more than six months after the latest CPI is released, the Monitor recommended using a 10-year average of CPI changes to escalate prices an additional year.
Dauphinais asked for more evidence supporting use of the PJM default values. “We’re very anxious to get those,” he said. “We’re missing some data here.” Chiasson said the Monitor would provide more information on PJM values at the next RASC meeting.
Del Mar became the second city in San Diego County — after San Diego — to announce an objective of moving to 100% renewable energy by 2035. That goal is part of a larger climate action plan to reduce the city’s greenhouse gas emissions.
In the latest chapter in their ongoing dispute, the City of Boulder and Xcel Energy are discussing a possible settlement that would end the city’s push to form a municipal electric utility.
The $12 billion merger between Southern Co. and AGL Resources, which would create the second largest utility in the U.S. by customer count, has cleared another hurdle, receiving approval from the Commerce Commission
The House of Representatives approved legislation that would require utilities to solicit long-term contracts for 1.2 GW each of Canadian hydroelectricity and offshore wind.
Battle Creek police arrested Joshua Buchanan on Thursday in connection to a firebomb found by workers at a Consumers Energy substation the day before.
The Public Service Commission has fined Consumers Energy $515,800 over failing to provide thousands of its ratepayers with accurate meter readings.
Coal production in the state declined by nearly a third during the first four months of 2016, with coal companies producing 4 million fewer tons so far this year.
The Antelope County Board of Supervisors approved a plan by Invenergy to erect 160 wind turbines. The supervisors imposed several conditions on the project, such as increased setback distances and completion of a noise analysis within 24 months after the structures are erected.
A local protest group has re-formed to oppose Jersey Central Power & Light’s proposal to build a $75 million transmission line between Aberdeen and Red Bank. The same group successfully fought the same transmission line project in the 1990s.
The state Court of Appeals has ordered the Utilities Commission to revisit its decision to require environmental activists to pay a multimillion-dollar bond in order to appeal the commission’s approval of a Duke Energy power plant near Asheville.
The Public Service Commission spent 10 hours last week listening to testimony and comments regarding NextEra Energy’s proposed 72-turbine, 150-MW Brady Wind Energy Center II.
The nominating council for the Public Utilities Commission has selected nine candidates from the 19 who applied for the vacancy left by outgoing Chairman Andre Porter.
A state task force is likely to recommend ways that legalized indoor marijuana growers can economize on their intensive use of energy and water rather than impose any limits on the booming horticultural business.
Daniel J. Mumford, who spent 26 years with the Public Utility Commission’s Bureau of Consumer Services, has been appointed director of the Office of Competitive Market Oversight. Mumford most recently helped direct the commission’s investigations into the state’s retail electric and natural gas markets and formulate changes in the wake of the polar vortex of 2014.
The House of Representatives voted 64-7 to approve a bill intended to block a $700 million natural gas-fired power plant proposed in Burrillville.
The Federal Aviation Administration ruled that 86 wind turbines planned for Chapman Ranch, near Corpus Christi, won’t be hazardous for air navigation, clearing a significant hurdle for the proposed wind farm’s developer, Apex Clean Energy.
Gov. Peter Shumlin vetoed a bill giving communities more say in the siting of wind and solar power projects.
The Madison City Council adopted a measure last week to cut the city’s emissions 80% by 2050.
Bowring also attempted to puncture any notion that scarcity pricing is much simpler than capacity markets.
The company vehemently denied allegations made by Attorney General Eric Schneiderman that it encouraged illegal tree cutting by landowners in defiance of a FERC prohibition, calling the complaint “part of a pattern seeking to delay construction.”
