The New England Power Pool Participants Committee urged federal regulators last week not to short circuit its stakeholder process in ordering zonal sloped demand curves for the next Forward Capacity Auction.
NEPOOL joined ISO-NE in asking the Federal Energy Regulatory Commission to reject a request by generators to force the RTO to develop a zonal sloped demand curve design for FCA 10 in February (ER14-1639).
The New England Power Generators Association made the request June 22 after ISO-NE backed off from its commitment to introduce a new curve for FCA 10, saying that making a change now would create reliability concerns. The generators asked FERC to reiterate a previous order that directed the RTO to continue efforts to eliminate administrative pricing in zones that are short of generation resources or suffer from transmission constraints. (See NEPGA: Order Sloped Demand Curve in FCA 10.)
ISO-NE withdrew its support for the change just before NEPOOL was scheduled to vote on it. At NEPOOL’s June Planning Committee meeting, only 42% of stakeholders backed the sloped curve.
NEPOOL told FERC that although some of its members feel “frustration” with ISO-NE for reversing course despite “substantial progress,” it wants any changes to result from the stakeholder process.
“NEPOOL takes no position under these circumstances on whether an order to implement sloped zonal demand curves generally is appropriate or justified,” it wrote. NEPOOL’s preference is to develop consensus in its own stakeholder process for “many interrelated issues,” it said.
The Electric Power Supply Association also weighed in on the issue last week, expressing support for NEPGA and chastising the RTO for its reversal. “EPSA does not believe that the commission intended the ISO-NE to receive a free pass on this issue,” it wrote.
In its reply to NEPGA, filed July 2, ISO-NE said the generators’ motion should be dismissed on procedural and substantive grounds.
“NEPGA’s proposed zonal demand curve design using potential FCA 10 capacity zone boundaries shows dramatically worse performance,” it said.
NEPGA had asked for a Section 206 proceeding, but the RTO said “it falls far short of what is required under the commission’s rules to initiate a proceeding.”
SPP’s Markets and Operations Policy Committee will vote this week on a recommendation to move the deadline for day-ahead market offers up 90 minutes to 9:30 a.m. CT.
The proposal, which has cleared four lower stakeholder groups, would have day-ahead results posted at 2 p.m. CT, up from 4 p.m. It also shortens the reoffer period to 45 minutes, with reliability unit commitment (RUC) offers due at 2:45 and results posted by 5:15.
The changes to SPP’s operating tariff are intended to comply with the Federal Energy Regulatory Commission’s Order 809, which moved the timely nomination cycle deadline for gas to 1 p.m. CT from 11:30 a.m. and added a third intraday nomination cycle. The commission ordered RTOs to adjust the posting of their day-ahead energy market and reliability unit commitment process results “sufficiently in advance” of the revised gas cycles, or explain why it is not suitable for their markets. (See SPP Trying to ‘Balance the Risk’ on Gas-Electric Schedules.)
‘Incremental’ Improvement
The revised timeline would not provide day-ahead market results before the 1 p.m. CT nomination deadline, but it would provide 30 minutes before the Intraday 2 nomination. RUC results would be available 45 minutes before the 6 p.m. evening gas nomination.
The proposal has already been endorsed by majorities in the Gas Electric Coordination Task Force (4-2 with two abstentions); the Market Working Group (7-5-5); Regional Tariff Working Group (14-2-3); and Operating Reliability Working Group (9-1-1).
The task force’s recommendation termed the changes “an incremental improvement over the existing timeline for improving coordination between the market results and the Timely and Evening nominations.” The group also said the changes will allow for day-ahead market and reliability unit commitments to be provided before the evening nomination and sufficient time in the morning for “price formation” before the day-ahead market closes.
SPP estimates it will take approximately $1.5 million and 14 months to implement the current changes, which would require FERC’s approval of the tariff changes and new software implementation. RTO officials’ long-term goal is to post day-ahead market results before the timely gas nomination.
Opposition in the North
The change was opposed by several members in SPP’s north, where cold weather affects natural gas supplies during critical time frames, including Lincoln Electric and the Omaha and Nebraska public power districts.
In stating its opposition, Nebraska Public Power District said SPP and its members should have taken their timeline concerns to FERC before developing a revision request. “Spending $1.5 million and not [getting] what we need … actually could make it worse for the market overall,” NPPD said.
NPPD and City Utilities of Springfield also said the change would hurt forecast accuracy, particularly for wind generation.
Springfield noted that SPP has a large share of intermittent wind generation — making forecasts especially important —while experiencing fewer gas constraints than eastern RTOs.
“The greatest benefits of [the change] impact less than 10 days a year (3%) at the detriment of the remaining 355 days,” Springfield said. “SPP has a relatively small percentage of gas generation in their average stack and a ~40% capacity benefit margin, which provides needed cushion in the current construct.”
SPP used social media recently to announce its membership had hit 90 with the addition of three cooperatives and an investor-owned utility that joined the RTO as part of the Integrated System.
East River Electric Power Cooperative is a wholesale supply cooperative serving 24 rural electric co-ops and one municipally owned electric system with a total of more than 92,000 homes and businesses. The cooperative has a 40,000-square-mile service area covering 63 primarily rural counties in eastern South Dakota and western Minnesota.
Northwest Iowa Power Cooperative is a generation and transmission cooperative supplying wholesale power to seven distribution co-ops serving more than 30,000 members and consumers. It covers 6,500 square miles in western Iowa.
Corn Belt Power Cooperative, another G&T cooperative, provides energy to nine distribution co-ops and a municipal co-op in 41 counties in northern Iowa.
NorthWestern Energy is an investor-owned utility providing electricity and natural gas to about 692,600 customers in Montana, South Dakota and Nebraska. It owns and operates wind, water, natural gas and coal-fired generation and delivers electricity to more than 416,100 customers.
SPP began coordinating transmission for the Integrated System on June 1. Full membership is expected in October. SPP has members from 14 states and 48,537 miles of transmission; the newest members will give SPP approximately 60,000 miles of transmission, stretching from northwest Louisiana, across the Great Plains to western Montana.
The amount of coal mined using the controversial mountaintop removal method has plummeted 62% in the past six years, according to the US. Energy Information Administration.
All coal production has decreased 15% because of lower natural gas prices and a decreasing demand for coal, according to EIA. But the drop has been more acute for coal recovered by mountaintop removal, which involves clearing rock and soil overburden to expose a coal seam. The method, used mostly in central Appalachia, and decried by environmentalists, sometimes results in valleys being filled in by the waste material.
Obama Administration Wants more Americans Getting Solar Energy
The Obama administration is introducing measures that will triple the capacity of solar and other renewable energy installed in subsidized housing to bring green energy to lower- and middle-income Americans.
The administration’s climate change initiative includes backing efforts to make it easier for homeowners to borrow money for renewable energy installations, primarily solar. Charities and investors also have committed to spending more than $520 million for solar and energy efficiency projects.
Senate Republicans Call for Revocation of NRDC’s Status
The National Republican Senatorial Committee is calling for federal authorities to revoke the tax-exempt status of the Natural Resources Defense Council because of its “partisan” campaign against Sen. Mark Kirk of Illinois.
The Republican committee said the NRDC’s campaign criticizing Kirk violates its nonprofit status, which prohibits it from engaging in political activity. Kirk is up for re-election in 2016.
The environmental group says the ads are purely educational. The NRDC’s campaign followed major campaigns by the League of Conservation Voters and the Sierra Club against Kirk.
DOE Providing $18 Million in Biofuels Research Projects
The Department of Energy is investing $18 million in six projects that aim to produce biofuels that would come to market for less than $5/gallon by 2019.
The projects, which seek to produce fuels or fuel additives from algal biomass, are underway at the Colorado School of Mines, Duke University’s Marine Algae Industrialization Consortium, Global Algae Innovations, Arizona State University, University of California/San Diego and Lawrence Livermore National Laboratory.
Energy Companies, Utilities Seek Last-Minute White House Meetings
Utility groups and energy companies are lobbying the White House before new carbon emissions regulations for power plants are released in August.
The White House has hosted at least eight meetings with industry groups in the past three weeks, including Duke Energy, manufacturer Honeywell and the National Mining Association. Opponents argue that the regulations imposed on states are too stringent, and the timetable is too short, to be reasonable.
“The point we left them was that in the Clean Power Plan, EPA is offering governors a basket of rotting carp,” said the NMA’s Luke Popovich.
NRC Approves Transfer of Nuke License to Duke Energy Progress
The Nuclear Regulatory Commission has approved the transfer of the operating licenses of the Harris Nuclear Plant and the Brunswick 1 and 2 plants from the North Carolina Eastern Municipal Power Agency to Duke Energy Progress. The transfers were part of Duke’s $1.2 billion acquisition of NCEMPA generation assets announced earlier this year. Closing of the deal is expected by the end of July.
VALLEY FORGE, Pa. — Tier 1 synchronized reserve resources would be obligated to respond in emergencies and subject to penalties if they couldn’t, under a PJM-backed proposal approved Wednesday by the Market Implementation Committee.
The proposal retains Tier 1’s ability to receive compensation outside of synch reserve events whenever the non-synch reserve market price is more than $0. Units could opt out of the performance obligation, but by doing so they would forfeit any credit they would have received outside of responding to an event.
Estimated Tier 1 megawatts would still be considered when clearing the synch reserve market so that opting out could not be used to withhold supply from the market and drive up prices.
In addition, units would be made whole for the cost of responding to a spin event. However, that would apply only to units scheduled by PJM to provide energy or self-scheduled resources that are dispatched by PJM to run above their minimum rate.
The PJM proposal was one of three presented to address a problem statement raised last fall by Independent Market Monitor Joe Bowring, who estimated that the payment scheme dating to 2012 results in about $85 million in unnecessary expenditures each year. (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)
The other plans were crafted by Bowring’s Monitoring Analytics and PJM’s Industrial Customer Coalition.
Bowring’s proposal would have eliminated the compensation Tier 1 resources receive when they’re not responding to an event — what he classified as an unearned “windfall” — and would not have imposed a performance obligation. It failed, garnering just 29% of the vote.
Bowring said Tier 1 resources already can offer as Tier 2. “All of the functionality that PJM wants to add through these complicated changes are already there,” under current rules, Bowring said, sparking a brief debate with Adam Keech, PJM‘s director of wholesale market operations.
Keech said it is up to PJM to decide whether to accept Tier 1 resources seeking Tier 2 status.
“No one can force PJM to buy Tier 2 it doesn’t need,” Bowring agreed.
The proposal from the ICC would have compensated Tier 1 resources outside of an event, but at the non-synchronized reserve price.
The ICC’s Susan Bruce said the proposal was a compromise between the approaches of PJM and the Monitor. “The Industrial proposal is smack dab in the middle between the two.” It was rejected with a favorable vote of just 23%.
PJM’s scarcity pricing scheme was created in 2012 to accurately price energy and reserves when reserves are short — defined as less than the largest generating unit that is on-line. The mechanism allows the market clearing price to rise, creating an incentive for resources to respond in an emergency.
PJM’s proposal, which passed with 64% approval, will be heard at the Markets and Reliability Committee next month. If approved there, it will be presented to the Members Committee in October and implemented shortly thereafter. Manual language will be presented at the August MIC.
Market participants would be able to enter replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year if the need is linked to a physical reason that would prevent a participant from meeting its commitment, according to manual changes approved last week.
To prevent the opportunity for financial arbitrage between auctions, the changes prohibit generation that is replaced early from being recommitted for the delivery year.
The motion passed with 81% support, trumping an alternate measure introduced by Tom Rutigliano on behalf of EMC Development. That proposal, which would have placed no restrictions on what capacity could be replaced or on it being re-entered into the market, received 28% support.
Under the approved changes, replacements would be permitted when the owner could show the expected final physical position of the resource at the time of the request.
Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project was canceled or delayed.
Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.
Package Calls for Notice on Pricing Interfaces
PJM would be required to provide more public notice before it creates “closed-loop” pricing interfaces under a proposal approved by the committee.
Under the changes, the RTO would announce the implementation of such interfaces at least five days before the close of the next monthly financial transmission rights auction. Currently, there are no notice requirements except for sub-zonal demand response, which is announced the previous day.
The RTO also will provide notice when it begins studying a potential new interface that will be defined and able to be used, such as looking into modeling the interface. Notices will be posted on the OASIS site, triggering an email to stakeholders. The rule will allow an exception to the advance notice requirements for planned, emergency or maintenance outages of less than 10 days.
PJM uses closed-loop interfaces to capture operator actions in LMPs rather than in uplift because its modeling software is unable to set prices for voltage problems.
The change was approved by acclamation with 10 members voting in opposition.
PJM told the Operating Committee last week it plans to poll members on whether to expand the winter preparedness testing it began last year. The testing was credited with improving generator performance during the winter of 2014/15, but it came at a cost of about $7 million to load.
Susan Bruce, of the PJM Industrial Customer Coalition, said her members had questions about whether the testing “is a good use of ratepayer dollars.”
“It’s not a slam dunk to us that this should be expanded,” she added.
Gregory Carmean, executive director of the Organization of PJM States, which represents state regulators, suggested generators — not load — should be shouldering the costs. “What’s the rationale for load paying these costs in a Capacity Performance world?” he asked.
However, Brock Ondayko of American Electric Power noted that the coming 2015/16 winter will not be subject to the Capacity Performance rules, which don’t take effect until delivery year 2016/17.
Dan Griffiths, executive director of the Consumer Advocates of PJM States, was more sympathetic to continuing the testing, calling it a “pragmatic question.” But he requested time to poll his members before voting.
“If it’s useful for identifying problems it should be done,” he said.
Members will be asked to vote on four options, which would be reflected in Section 7.5 of Manual I4D:
Option 1, with the addition that the program would end after winter 2015/16 for CP resources.
Option 1, plus the following changes: Expand the exercise period from the month of December to the months of November through January; expand the maximum temperature for the testing to 40 degrees Fahrenheit in PJM’s southern zones (from 35 F); allow testing of more than 1,000 MW/day.
Option 3, with the program terminating after winter 2015/16 for CP resources.
In a survey in June, all but three of 119 respondents said they supported continuing the testing; 93 (78%) said they preferred maintaining the current rules while 26 (22%) favored making some changes, which were not specified. (See Why Did PJM Grid Fare Better This Winter?)
PJM Seeking to Tighten Training, Certification Rules
PJM will seek OC approval next month on an initiative to improve compliance with the RTO’s training and certification requirements.
The requirements cover transmission owners, generation dispatchers, demand response providers and energy storage device operators. While transmission owners are usually in compliance, PJM said in a problem statement, non-compliance by some in the other groups “has been continuing for many months and in many cases has increased or become chronic in nature.”
Although those not in compliance are required to submit mitigation plans, most have not done so or have failed to comply with them.
In June, nine generating companies, five small generators (>75 MW) and four DR and storage providers were out of compliance with training or certification requirements. Aside from seven of the generators, none had submitted mitigation plans.
PJM said the problem could lead to operational or reliability problems as some members are unaware of their responsibilities for providing instantaneous reserves and other generator data.
Glen Boyle, manager of system operator training, said the RTO hopes to complete the work, which it is recommending be conducted by the System Operations Subcommittee, within three months. “We’ve talked internally and have some options” for solutions, he said.
PJM said it will not consider changing the existing training and certification requirements within the scope of the problem statement.
Disconnect Between PJM, Members on Meter Accuracy
A proposed update of Manual 1: Control Center Requirements has exposed a gap between PJM and some transmission owners regarding accuracy requirements for system control and monitoring meters.
As a result — at PJM’s request — members last week endorsed changes to the manual except for Section 5.
“We need more time” before changing Section 5, PJM’s Ryan Nice told the OC. “PJM needs a better overall picture of the accuracy of metering data.”
While the manual requires accuracy of ± 2% for meters supplying data to PJM’s energy management system (EMS), it’s not clear that all meters are covered by that requirement. Some TOs have meters that are only accurate to within 3%, Nice said.
The gap affects real-time meters, not billing meters.
“We need to evaluate the cost” of requiring all meters to comply with the 2% requirement, Nice said, “to make sure the operational value justifies the cost and time to members.”
The General Assembly has exempted from public review some communications among members of the Public Utilities Regulatory Authority.
The legislature approved a bill exempting communications that occur between scheduled meetings after the regulatory agency said its communications were hampered by requests citing the Freedom of Information Act. Comments in public meetings are not exempt.
The three commissioners said they decide “complex, legal and technical matters” and discussions at public meetings can take hours.
Electric retailer North American Power has agreed to pay $2.6 million to settle complaints by state authorities that the company quickly increased rates for customers it had enrolled with a low introductory rate.
The supplier will pay $100,000/month over the next 26 months to Operation Fuel, a nonprofit that provides home energy assistance to residents. The settlement resolves a two-year investigation by the Public Utilities Regulatory Authority. The company made no admission of wrongdoing under the terms of the settlement.
Power Grid Upgrades Fail to Speed ComEd’s Restoration Times
Commonwealth Edison did not improve the time it took to restore power last year despite having spent more than $600 million to pay for smart grid improvements, raising questions about the effectiveness of the improvements.
ComEd’s restoration time averaged 196 minutes, according to its annual reliability report. The findings raised questions about the 2011 smart grid law, which allowed the utility to raise rates to finance a $2.6 billion grid modernization program over 10 years. ComEd also reported an average of just over one outage per customer last year, compared with 1.16 in 2012 and .99 in 2013.
Chief Operating Officer Terence Donnelly defended the utility’s performance, saying ComEd’s success in preventing outages has led to a longer average restoration time. “The outages that [occur cause] more significant damage and take longer to repair,” he said.
Gov. Mike Pence has written to President Obama stating the coal-dependent state will not comply with the Clean Power Plan unless major revisions are made. Pence said the plan would force premature retirement of coal-fired plants, “threatening our stable source of affordable electricity.”
The state would have to curb carbon dioxide emissions by 20% by 2030 under the plan that the Environmental Protection Agency is set to finalize in August. The state’s power plants ranked No. 4 in the U.S. in 2012 for the amount of CO2 emitted per unit of electricity.
Pence has repeatedly stated that he isn’t convinced that climate change is mostly caused by human activity, and he vowed the state was ready to use all legal means necessary to fend off EPA’s plan.
Anti-pipeline groups submitted more than 2,500 written statements with the Utilities Board to protest the Dakota Access pipeline, which would deliver 570,000 barrels of North Dakota crude oil across the state to Illinois.
“This huge hazardous liquid pipeline is threatening our land, our water and our very livelihoods, if not lives,” said Brenda Brink, of the Iowa Citizens for Community Improvement. “There’s not enough money in the world that they can give us to cross our land, they’ll never do it,” said Dick Lamb, a landowner.
The pipeline proposed by Energy Transfer Partners would cross four states.
A report by The Brattle Group concluded that the Calvert Cliffs nuclear energy plant contributes $397 million to Maryland’s gross domestic product and accounts, directly and indirectly, for 2,300 full-time jobs.
The study estimated that without the Exelon-operated plant, Maryland’s carbon dioxide emissions would be about 9 million tons higher.
The industry-commissioned report comes at a time when some U.S. nuclear facilities – including several of Exelon’s units in Illinois – are facing potential shutdowns due to economic and policy challenges. In Illinois, Exelon has proposed legislation that would help shore up its underperforming plants. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)
Gov. Charlie Baker is supporting legislation that could help import up to 2,400 MW of Canadian hydropower into the state.
Matthew Beaton, Baker’s energy and environmental affairs secretary, said the state needs more electricity from renewable energy sources such as hydropower if it is to meet a 2020 deadline for reducing greenhouse gas emissions.
Baker’s bill would require major electric utilities to seek long-term contracts from hydropower generators — most likely Canadian companies such as Hydro-Quebec and Nalcor Energy.
The Public Service Commission on July 9 approved the construction of solar facilities near the Golden Triangle Industrial Park and at Golden Triangle Regional Airport in Lowndes County. The two facilities will cost nearly $3 million and generate a combined 1.6 MW.
The new solar sites are among several approved by the commission this year. “The momentum is really picking up in Mississippi on solar power,” Commissioner Brandon Presley said.
Silicon Ranch Investments and SR Walker East will build, operate and maintain the arrays.
State regulators are set to approve a plan to allow Liberty Utilities to secure 115,000 dekatherms of daily capacity on Kinder Morgan’s proposed natural gas pipeline from the Marcellus Shale formation in Pennsylvania into New England.
The staff of the Public Utilities Commission signed off on the utility’s request to use the Northeast Energy Direct project to serve its 90,000 customers. The three-member commission still has to formally approve the deal after a July 22 hearing.
Representatives of the Pipeline Awareness Network, an advocacy group, criticized the PUC’s staff for endorsing the project despite testimony of the PUC’s own expert witness and the agency’s consumer advocate that questioned the need for the utility to procure such a large amount of capacity.
Residential air conditioners can be turned down by remote control during times of peak demand under a limited, voluntary program that began July 1.
Participating customers will be paid small stipends to take part in the program and could save an estimated $100/year or more through lower electricity use during times when the AC is dialed down. For now, Rochester Gas & Electric is offering the program only to certain customers in two towns in Ontario County. RG&E’s sister company, New York State Electric and Gas, is offering its program in similar high-demand pockets in southern Erie, Chautauqua and Putnam counties.
New York regulators mandated the initiative as part of the overhaul of the state’s energy distribution system, known as Reforming the Energy Vision. The hope is that “dynamic load management” programs will relieve stress on the electric distribution system and help consumers learn to better manage their own energy use.
Electric retailer HIKO Energy has agreed to pay $1.25 million to settle fraud claims by the state attorney general.
The attorney general’s lawsuit accused HIKO of defrauding 25,000 current and former customers between June 1, 2011, and Oct. 1, 2014. An investigation by the Consumer Protection Bureau found that the company promised lower rates to customers and then charged higher rates, enrolled new customers without their knowledge and made it difficult for customers to cancel their enrollment.
The settlement requires HIKO to pay $1.25 million to the attorney general’s office to be used in a restitution program.
Solar energy capacity in the state quadrupled from 2011 to 2014, which officials say is a sign that solar power is becoming a more significant factor in meeting the state’s energy needs.
By the end of last year, state residents had installed enough solar energy-generating capacity to produce 314.5 MW. In April, solar power accounted for nearly 0.1% of the state’s electricity production, according to the U.S. Energy Information Administration.
The amount of electricity generated from solar energy tripled in Western New York over the last three years, thanks to a combination of lucrative government incentives and a steady decline in the cost of rooftop solar energy systems, according to a new report from the New York State Energy Research and Development Authority.
In addition to a 30% federal tax credit on new solar energy systems, the state is offering $1 billion in incentives for larger-scale solar projects through its NY-Sun initiative.
The state is awarding $100,000 in grants to 83 groups for microgrid projects through a competition that is designed to promote small-scale, community-run electric generation.
The winners include Central Hudson Gas & Electric and NRG Energy, which have partnered to evaluate the potential of a resilient microgrid at Stewart International Airport that would also benefit critical facilities in New Windsor. If the project study is approved, it may be eligible for up to $1 million for development of detailed designs and up to $7 million for construction.
Pork Producers Ask Lawmakers to Keep Renewable Mandate
The state’s pork producers are asking lawmakers to maintain a provision in the state’s renewable energy law that requires a small percentage of power to be derived from swine manure.
The state’s utilities are asking, for the fourth year in a row, that the targets in the 2007 renewable energy law be postponed because no producers have been able to meet them. But some pork producers say they have already invested millions to develop manure management systems to capture methane from swine waste as an alternative to lagoon storage and field spraying. Smithfield Foods, the largest pork producer in the U.S., has spent $40 million developing projects at six of its hog farms.
“We don’t want to see anything about the law get changed,” Angie Maier, the N.C. Pork Council’s policy development director.
PSC Sees ‘Continual Stream’ of Pipeline Applications
Despite the downturn in oil prices, the Public Service Commission is seeing “a continual stream of applications” for crude oil pipelines from oil-producing areas.
Commissioner Randy Christmann said the applications for infrastructure investment in the Bakken Shale oil-producing areas is a bullish sign for the oil-producing state, despite the slowdown in drilling. “It is going to make the next time it picks up … far more pleasant,” Christmann said.
The PSC approved a siting application for a new pipeline last week and set a September hearing for a new 23-mile crude pipeline by NST Express.
Local Officials Appeal to Governor for More Control over Drilling
Some municipal and county officials have asked Gov. John Kasich to grant more control to local government over oil and gas drilling.
“The notion that our communities have the right to bar or limit activities which threaten public health or the quality of life of their residents has a long tradition in Ohio law,” the officials state in a letter to the governor, which was released by the anti-drilling group Environment Ohio. “… Yet the oil and gas industry has the audacity to insist that this basic principle of local control should not apply to its operations.”
Groups Accuses AG’s Office of Failing to Conduct Fracking Health Probe
Advocacy group Food & Water Watch has accused the attorney general’s office of failing to follow through on a promise to investigate complaints that the state Department of Health discounted reports of residents who said they had been sickened by hydraulic fracturing.
The group said Attorney General Kathleen Kane’s office had done only “a few cursory interviews” instead of a full investigation. It has filed a right-to-know request seeking any documents relating to public health complaints and fracking.
A spokesman for the Democratic attorney general’s office said it attempted to look into the allegations but were stymied by the Health Department, which was controlled by a Republican administration until January. “Our environmental crimes unit did pursue this investigation and interviewed a significant number of the complainants,” a spokesman said. “But because the Department of Health under the last administration was not cooperative, it was difficult to determine how they responded.”
The Public Utilities Commission has eliminated a “billing adjustment” charge assessed on electricity customers who switch from incumbent utilities to competitive suppliers.
The billing adjustment charge, which was put in place in 2010, was designed to compensate utility National Grid for the difference in the fixed rate it charges consumers for electricity and the underlying variable rates it pays to power generators from month to month.
The commission said the charge caused confusion among customers and inhibited the growth of competitive retail electricity markets.
Judge Grants Eminent Domain to Dakota Access Pipeline
A county judge granted eminent domain status to the Dakota Access crude oil pipeline, although the state Public Utilities Commission has not yet approved the project that would deliver North Dakota petroleum though the state.
The judge’s ruling will make it easier for surveyors to develop a route for the pipeline, which would run about 272 miles across the state. Dakota Access filed for the status in April, saying it was necessary for the surveyors to determine a suitable route for the pipeline.
Energy Transfer Partners is building the project, which would deliver 450,000 barrels of crude oil a day on a 1,134-mile route that terminates at a rail terminal and pipeline interconnection in Illinois.
Dominion Transmission has filed proposed route changes for its Atlantic Coast Pipeline through southern Virginia to more closely align the natural gas pipeline’s path with existing rights-of-way.
But Dominion has not altered the route through the western part of the state, where opposition to the project is strongest. “We’re still exploring new opportunities for routes, refinements and adjustments,” said Greg Parks, construction supervisor for the $5 billion, 550-mile pipeline project.
Dominion said that it is more difficult to co-locate the pipeline with existing utility corridors in the mountainous western region of the state.
Lawmakers Try to Clear County Block of Enbridge Pipeline
Republican lawmakers have proposed to strip a county government of the authority to demand that a crude oil pipeline obtain more insurance.
The lawmakers added language to the state budget bill aimed at Dane County, which required a crude oil pipeline operator to boost its insurance coverage. That requirement has impeded completion of upgrades that Enbridge is installing on its Line 61 pipeline from Superior to Illinois. The upgrades would double the daily capacity of the 343-mile pipeline from 560,000 barrels to 1.2 million barrels. The language also allows the company to increase the pipeline’s capacity in the future, without requiring county approval.
Enbridge said the county exceeded its authority since federal agencies regulate interstate pipelines. Enbridge also said that it has always been responsible for the costs of cleanups. But environmental groups protested the language, noting that Enbridge has a history of pipeline spills in the state.
State regulators, consumer advocates, generators and the Independent Market Monitor have asked the Federal Energy Regulatory Commission to modify its June 9 order largely approving PJM’s Capacity Performance plan.
Most of the rehearing requests were filed Thursday, along with PJM’s submission of a 556-page compliance filing responding to the commission’s request for changes to its plan.
Maryland and D.C. regulators asked the commission to reverse the order, while generators sought relaxation of penalty provisions. Two filings seek expedited review before PJM’s “transition” auctions begin July 27.
Load Forecast
One asked FERC to order PJM to update its peak load forecasts for the upcoming capacity auctions or delay them (EL15-83).
The complainants — the PJM Industrial Customer Coalition, the Sustainable FERC Project and regulators or consumer advocates from Delaware, D.C., New Jersey, Maryland, Pennsylvania and West Virginia — say that PJM’s newly designed load forecast could reduce the amount of capacity procured by approximately 7,000 MW, saving consumers about $625 million.
(Click to zoom.)
While PJM told stakeholders at the May Load Analysis Subcommittee meeting that the new model is a “noticeable improvement” over the current forecast, the plaintiffs say, the RTO has said the new forecasts won’t be ready for incorporating in the capacity auctions until November.
The transition auction for delivery year 2016/17 is set for July 27-28 and that for 2017/18 for Aug. 3-4. The Base Residual Auction for 2018/19 is scheduled for Aug. 10-14.
The plaintiffs say FERC should either order use of the new models under the current auction schedule, delay the auctions until November or reinstate the short-term resource procurement target — also known as the “2.5% holdback” — for the BRA. FERC eliminated the holdback in its June 9 ruling. (See FERC OKs PJM Capacity Performance: What You Need to Know.)
They asked FERC to rule by July 17, saying continued use of the current model “will lead to substantial and imprudent over-procurement of capacity, resulting in unjust and unreasonable capacity prices for consumers.”
The plaintiffs said PJM has overestimated the RTO’s reliability requirement by an average of 6.25% in delivery years 2010/11 through 2015/16. The new model attempts to better account for energy efficiency and other factors.
PJM Vice President of Planning Steve Herling told RTO Insider on Thursday that the RTO reworked its load forecasting model with a focus on how it would affect the regional transmission expansion planning process. “We have not even begun to figure what the implication will be for” the capacity market, he said. “It started as an RTEP issue.”
In addition, he said, there is more work to do, including updating zones with new metropolitan area mapping and investigating the current practice of using 40-plus years in weather simulations. And, he added, the model has yet to pass through the stakeholder process. “Any change like that has to go through a vetting process,” he said.
Annual DR
Most of the same complainants — along with the Public Power Association of New Jersey, Duquesne Light Co. and regulators and consumer advocates from Illinois — also are seeking expedited hearing of a complaint seeking to allow annual demand response resources to bid into the transition auctions.
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The plaintiffs acknowledged that the commission’s June 9 order “did not discuss specifically” whether annual demand resources could participate in the transition auctions. “This specific issue was not raised for the commission’s consideration because, ostensibly, it was clear from the operative provisions of the as-filed version of Section 5.14D [of PJM’s Tariff] that the transition auctions applied to all Capacity Performance resources, which, by definition, includes annual demand resources and other types of resources.”
The complainants said PJM has told them and other stakeholders that the Tariff does not permit annual DR’s participation.
“PJM’s view is that only generation capacity resources are eligible to participate in transition auctions. PJM has acknowledged, however, that no operational basis exists for excluding annual demand resources from the transition auctions. It appears that PJM’s concern is whether sufficient bases exist under the Tariff language that has been accepted by the commission to allow all types of Capacity Performance resources to participate.”
PJM has not responded to the filing, but in a separate challenge by the Advanced Energy Management Alliance Coalition, the RTO said Thursday it intended to exclude DR and energy efficiency from the transition auctions.
PJM said the transition auctions were designed to “provide a glide path” for generation resources that needed time to make investments to meet Capacity Performance requirements.
“The decision to limit the transition auctions to generation capacity resources was made in light of the fact demand response resources or energy efficiency resources would not need the same glide path, and also taking into account the continued uncertainty associated with the availability DR and EE to serve as Capacity Performance resources” following the D.C. Circuit’s EPSA ruling voiding FERC’s jurisdiction over DR (EL15-80). (See Supreme Court Agrees to Hear Demand Response Appeal.)
Market Monitor: ‘Inconsistent’ Incentives
The Monitor requested FERC revise findings in its June order that it said “create incentives in the energy market that are not consistent” with the Capacity Performance market design.
The Monitor cited FERC’s rejection of PJM’s proposal to allow parameter limits based only on resources’ physical constraints, saying the commission’s action would result in increased uplift payments.
“By permitting generation owners to establish unit parameters based on non-physical limits, the … order has weakened the incentives for units to be flexible and has weakened the assignment of performance risk to generation owners,” the Monitor said. “Contractual limits, unlike generating unit operational limits, are a function of the interests and incentives of the parties to the contracts. If a generation owner expects to be compensated through uplift payments for running for 24 hours regardless of whether the energy is economic or needed, that generation owner has no incentive to pay more to purchase the flexible gas service that would permit the unit to be flexible in response to dispatch.”
In contrast, NRG Energy and Dynegy asked FERC to clarify that capacity resources will not be penalized if PJM does not schedule them or reduces their output as the result of parameter limitations approved by the RTO.
The Monitor also called for changes regarding eligibility and documentation of risk premiums, the sub-zonal dispatch of DR and the calculation of “performance hours” and peak load obligations.
State Regulators Fear Higher Prices
The Illinois Commerce Commission said the commission’s order will create unnecessary barriers to market entry and undermine market power mitigation, resulting in higher costs for consumers.
The ICC said FERC erred in eliminating unit-specific cost reviews and the 2.5% holdback. It also faulted FERC for limiting the types of resources permitted to aggregate for the purpose of performance measurements, and in prohibiting external resources lacking pseudo ties from offering as Capacity Performance.
The Pennsylvania Public Utility Commission and the Delaware Public Service Commission joined the ICC in challenging the commission’s changes to PJM’s market mitigation rules and the elimination of the 2.5% holdback. They also questioned how penalties will be calculated; changes to credit requirements; the transition mechanism; and the elimination of extended summer DR and limited DR.
The Delaware commission also filed a separate rehearing request asking FERC to “identify the components of the balance upon which it relied for the determination that the market rule changes were just and reasonable” and asking that PJM be required to make informational filings regarding the costs and benefits of the new rules.
“Without such a requirement from this commission, any information and/or data would only be available on an ad hoc basis, which would not provide an appropriate foundation for the commission to make any assessment as to the ultimate cost effectiveness to customers of [Capacity Performance] and, perhaps more importantly, whether the costs for the implementation of [Capacity Performance] are appropriate and necessary,” Delaware said.
Generators: Penalties Excessive
The PJM Power Providers (P3) Group supported the commission’s ruling but asked FERC to clarify that generators operating within their approved parameters would not be subject to non-performance penalties. It also asked for clarification on what “performance quantifiable risks” can be included in avoidable cost risk calculations for units seeking to submit offers above the market seller offer cap. Exelon also requested rehearing on the issue.
“While both PJM and the commission expressly supported Tariff provisions that allow risks of fulfilling the obligation to offer capacity to be reflected in capacity offer cap calculations, the commission should go one step further and direct PJM to specifically enumerate known risks in addition to permitting the reflection of all reasonable risks undertaken to support a capacity offer,” P3 said.
Essential Power, Competitive Power Ventures, NextEra Energy and Invenergy Thermal Development contested FERC’s decision to eliminate monthly stop-loss limitations from PJM’s proposal, saying it failed to justify its decision through “reasoned decision-making.”
The coalition also said the commission erred in deciding that generator non-performance should not be excused even in circumstances beyond the control of generators, such as catastrophic weather events, compliance with state-approved tariffs or PJM-approved transmission outages.
GE Energy Financial Services, the operator of the 1884-MW Homer City coal-fired generating plant in Indiana, Pa., challenged FERC’s decision to make generators liable for a failure to deliver due to problems with transmission lines and switchyard equipment outside plant boundaries.
It said FERC was wrong in agreeing with PJM that generators were the market participants best able to bear the risk of transmission outages. “The best-placed party to bear this risk is the relevant transmission owner (and through it, load), which already collects payments to maintain these facilities,” it said.
“Unlike the ‘strict liability’ standard for generation delivery included in the CP revisions, transmission owners have limited their liability based on the customary ‘prudent industry practice’ standard. Thus, a supplier may have no recourse at law against its transmission ‘vendor’ — a sole source provider — even though the transmission owner has been paid to provide the service that it failed to deliver.”
The generator acknowledged that PJM may designate a transmission outage as a “catastrophic force majeure” that excuses generators for non-performance. But it noted “those events are intended to be region-wide in nature, even though Homer City will be equally unable to deliver its power upon the failure of its local transmission lines.”
“The penalties assessed against Homer City in that event would be funneled to other, luckier resources, which were fortuitously not in the wrong place at the wrong time.”
Public Service Enterprise Group also asked the commission to reinstate the existing force majeure provisions.
Calls for Reversal
While most of the filings sought to tweak the new rules, regulators from Maryland and D.C. argued that FERC should reverse its approval of PJM’s overhaul of the capacity market, saying it is “unnecessary for reliable service operations” and will increase end user costs in PJM by as much as $6 billion.
The commissions said the penalty provisions are not consistent with the higher revenues expected under the changes and said it should have held evidentiary hearings over the cost effectiveness of the changes. They also contend that the transition auctions are unnecessary.
Public Citizen also asked the commission to reverse its approval, citing the dissent by Chairman Norman Bay, who contended PJM’s overhaul of the capacity market was unwarranted. (See Norman Bay’s Dissent: ‘Two Carrots and a Partial Stick’.)
The group also asked that the commission review rates resulting from future capacity auctions under its “just and reasonable” standard.
“Public Citizen does not believe that the findings in this case are supported by ‘substantial evidence,’ but rather by the commission’s desire to further its market-based experiments in promoting and enabling ISOs and RTOs. Public Citizen fears that in doing so, however admirable its original intentions may have been, the commission may have lost sight of the primary goal of the [Federal Power Act], the protection of ratepayers from excessive rates and charges, and in fact may be slowly conceding its ability to protect ratepayers at all.”
Spanish energy giant Iberdrola SA on Tuesday dropped its bid to acquire UIL Holdings but promised to file a new application by the end of the month that would address objections raised by Connecticut regulators.
The Connecticut Public Utilities Regulatory Authority issued a draft decision June 30 that lambasted the companies’ application, recommending a final rejection, while giving them a week to respond. PURA said the acquisition was not in the public interest and offered no benefit to consumers. (See Connecticut Regulators Threaten to Reject Iberdrola-UIL Merger.)
The companies last week asked for a 60-day extension to address the decision, which outlined conditions including “ring fencing” of the local utilities, a three-year rate freeze and a commitment to keep their headquarters in the state for seven years. PURA immediately rejected that request as not affording enough time for adequate review and said the companies should file a new application that resets the clock at 120 days.
“The applicants hereby withdraw the pending application, in order to have the docket terminated as of this date and the remaining procedural schedule cancelled, which would, in turn, facilitate the applicants’ filing of a new application,” Iberdrola wrote.
Iberdrola has offered $3 billion for Connecticut-based UIL, including its United Illuminating electric distribution utility and three gas distribution companies in Connecticut and Massachusetts.
In a separate filing made hours before the companies dropped their bid, the Connecticut Industrial Energy Consumers praised the PURA draft decision. “CIEC commends the authority for reaching conclusions regarding the public interest of the proposed transaction commensurate with the record evidence,” the group wrote.
In mid-day trading, UIL stock shot up $1.46 after the announcement to $47.19.
PURA said June 30 it would not approve the deal without “ring fencing” provisions to protect UIL’s Connecticut electric and gas distribution companies from bankruptcies by Iberdrola’s other operations.
Regulators also said they “cannot conclude that the applicants will continue to possess the ability to provide safe, adequate and reliable service to the public.” It said Iberdrola’s financial strength and managerial expertise were adequate, but the company did “not possess the requisite suitability and responsibility to acquire UIL Holdings.”
A crowded docket has delayed several key pieces of New York’s Reforming the Energy Vision, including the Department of Public Service staff’s Track 2 straw proposal on ratemaking and rate design.
That document — originally expected in January and then delayed twice to June 1 and July 1 — is now due on July 28, along with staff-proposed rules governing commission oversight of distributed energy resource suppliers.
The New York Public Service Commission secretary on Tuesday granted extensions to commission staff and a working group that faced July 1 deadlines. “These extension requests are generally premised on the need to address concerns expressed by parties and members of the public for relief from the potential burdens imposed by the simultaneous issuance of four products in this proceeding,” the secretary wrote.
In requesting the delay, commission staff noted the overlap among the proposals, its own workload and the public comment periods for each.
The Market Design and Platform Technology Working Group report is now expected on July 13.
The August 2014 Track 1 straw proposal preceded the first REV order, which created the framework for development of clean and distributed energy resources. That led to the February PSC order that also set the schedule for these four docket items. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
“Track 2 will propose specific regulatory reforms to the utility business model, rate-making approaches and rate design to achieve REV policy goals,” according to the Rocky Mountain Institute, an advisor to the PSC.
NEPOOL joined ISO-NE in asking the Federal Energy Regulatory Commission to reject a request by generators to force the RTO to develop a zonal sloped demand curve design for FCA 10 in February (ER14-1639).
