FERC last week approved a settlement in a dispute between WPPI Energy and MISO over how to allocate voltage and local reliability (VLR) costs to pseudo-tied load (ER12-678-006).
The commission also granted WPPI rehearing in a related case, ordering MISO to pay refunds from September 2012 rather than July 2014 in a reallocation of costs for revenue sufficiency guarantees paid to resources providing VLR support (ER12-678-004, EL14-58-001).
In 2012, FERC approved MISO’s proposal to allocate VLR costs to all loads in a local balancing authority area (BAA), including pseudo-tied loads — load that is effectively transferred from a source local BAA, in which that load is physically located, to a different host (or “sink”) BAA. In a later order, the commission had reasoned that “the local BAA of the host load is responsible for voltage management in the pseudo-tied local BAA, and therefore MISO’s proposal comports with cost causation.”
FERC reversed course in June 2014, saying it had “erred” in approving MISO’s cost allocation and setting the issue for settlement discussions.
The commission said the settlement resolves the issue of “whether MISO should allocate VLR costs incurred in responding to a localized constraint to a market participant such as WPPI based on its load that is physically remote from the constraint, because that load has been pseudo-tied into the LBA area affected by the constraint.”
The settlement will revise MISO’s Tariff by adding a new term, “internal commercially pseudo-tied load,” and new language requiring submission of meter data by market participants that have such loads. MISO agreed to resettlements of WPPI’s VLR payments as soon as possible after the installation of necessary software changes and WPPI’s submission of required meter data.
In the related order, the commission agreed with WPPI that refunds from the reallocation should be effective as of Sept. 1, 2012, the date MISO’s original rate proposal went into effect, rather than July 9, 2014, the date FERC originally set.
FirstEnergy will retire four units at its largest coal-fired power plant in Ohio and sell or deactivate its Bay Shore plant by 2020, the company said Friday, citing “challenging market conditions.”
Together, the units represent 856 MW, of which 136 MW is generated by Bay Shore in the City of Oregon, Ohio. Units 1-4 of the seven-unit W.H. Sammis Plant in Stratton produce 720 MW. The remaining two units there will continue to provide 1,490 MW of baseload generation.
Sammis Power Plant Source: Bechtel
The 78 employees at Bay Shore would be offered jobs elsewhere in FirstEnergy if that plant were deactivated, and the company would work with any potential buyer to arrange their retention. Likewise, the 368 employees at Sammis would be offered other job opportunities, the company said.
Last year, the units headed toward closure or sale generated 4% of the electricity produced by all of FirstEnergy’s plants.
“We have taken a number of steps in recent years to reduce operating costs of our generation fleet,” FirstEnergy Generation President Jim Lash said in a statement. “However, continued challenging market conditions have made it increasingly difficult for smaller units like Bay Shore and Sammis Units 1-4 to be competitive. It’s no longer economically viable to operate these facilities.”
The announcement comes as the staff of the Public Utilities Commission of Ohio has proposed a rider for FirstEnergy that would allow it to recover $131 million annually from customers over three to five years so it may retain an investment-grade credit rating as it struggles to maintain some of its aging, mostly coal-fired plants. (See PUCO Staff Recommends $131M Annual Rider for FirstEnergy.)
FERC in April had ruled that an eight-year power purchase agreement PUCO had approved for FirstEnergy, and another for American Electric Power, would be subject to federal review. The ruling prompted FirstEnergy to return to PUCO with a modified proposal that commission staff said should be rejected in favor of the recommended rider.
FirstEnergy’s announcement was welcomed by environmental advocates who had denounced the company’s power purchase request as a corporate bailout.
“Closing these outdated, dirty power plants not only shows FirstEnergy finally recognizes the market momentum toward coal’s inevitable demise, the decision is great news for Ohio customers, who avoid paying a massive subsidy to keep the units afloat,” said Dick Munson of the Environmental Defense Fund.
According to the Sierra Club, FirstEnergy’s announcement brings the total amount of coal generation that has retired or is set to retire in the state since 2010 to 10,093 MW.
“Today’s announcement is further proof that Sammis is an outdated and costly coal plant that customers should not be forced to prop up,” said Shannon Fisk of Earthjustice. “We will continue to fight efforts that could be used to bail out other FirstEnergy coal units, as now is the time for significant investments in renewable energy, energy efficiency and grid modernization activity that will create jobs and economic development throughout Ohio.”
Bay Shore Unit 1, whose boiler is fueled by petroleum coke, went online in 2000. Units 2-4 were deactivated in 2012 because of environmental regulations.
Units 1-4 at Sammis date to 1959 through 1962. Units 5-7 came online from 1967 to 1971.
According to FirstEnergy, it pays $1.7 million annually in Bay Shore property taxes. The company pays more than $7 million in property taxes on the Sammis plant, making it the largest taxpayer in Jefferson County.
An agreement between FERC and the U.S. Army Corps of Engineers could help spur the development of privately run hydroelectric resources at the Corps’ unpowered dams.
The two agencies on Thursday signed a memorandum of understanding (MOU) to synchronize their processes to shorten permitting times, provide more certainty in regulatory outcomes and reduce financial risk for nonfederal project developers.
AMP’s Smithland project in Kentucky will divert water from the Corps’ locks and dams to generate 76 MW of electricity.
“The potential for hydropower development in this country is significant, particularly at existing Corps facilities,” FERC Chairman Norman Bay said. “Today’s MOU is a positive step toward the development of these resources.”
A 2012 Department of Energy study identifying 6,900 MW of potential hydroelectric capacity at the Corps’ unpowered dams sparked interest in development at the agency’s water projects, according to Tim Welch, the department’s hydropower program manager.
The Corps is authorized to allow nonfederal entities to develop hydroelectric projects at its facilities provided that the project’s operation is deemed compatible with the purposes of the facility and the federal government has no competing development interest.
“This synchronized approach will shorten the time it takes the private sector to develop and construct new hydropower and will help us more efficiently use our existing infrastructure,” said Jo-Ellen Darcy, the Army’s assistant secretary for civil works. “It is also advancing our efforts to find alternative ways to finance new infrastructure.”
The synchronized process consists of two overlapping phases in which the Corps’ environmental and engineering reviews occur simultaneously with the commission’s processing of the hydropower license application. The agencies had been conducting their permitting processes sequentially.
During the first phase focused on environmental impact, FERC and Corps staff will collaborate with a project developer to understand the proposal and communicate the agencies’ permitting requirements.
As the lead agency under the National Environmental Policy Act responsible for licensing hydroelectric projects, FERC will direct preparation of the environmental permit for a proposed project, coordinating with its sister agency to ensure that a final document is consistent with the Corps’ statutory obligations. Once the joint environmental impact review is complete, FERC will issue a license.
The second phase will entail a technical, engineering and safety review after the developer has submitted a final project design. The developer will coordinate with the Corps to ensure construction won’t compromise the structural integrity of the agency’s facility. Once those requirements are met and communicated to FERC, the commission will authorize the project’s construction.
The MOU makes explicit that, as a cooperating agency in the process, the Corps is prohibited from later intervening in any FERC proceeding related to a project’s approval.
The commission has licensed nearly 30 nonfederal hydroelectric projects with a combined capacity of 400 MW at Corps facilities since 2007, said Nick Jayjack, deputy director of FERC’s Division of Hydropower Licensing. Five projects rated at about 133 MW are currently under construction, while 18 license applications representing another 500 MW are in the commission’s review pipeline.
Non-jurisdictional SPP members that refused to agree to potential refunds of revenues from the RTO’s seams settlement with MISO can be denied distribution of settlement proceeds, FERC ruled last week (ER16-791).
The ruling clarified the commission’s March order accepting SPP’s proposal to distribute to its members $16 million in funds reached in a settlement with MISO over the latter’s use of SPP’s transmission system to transfer power freely between its North and South regions. The order set the docket for hearing and settlement procedures to resolve factual issues in dispute. (See SPP Asks for Clarification on MISO Settlement Order.)
SPP asked the non-jurisdictional transmission owners to promise refunds of the revenues in case the allocation methodology changes as a result of the settlement procedures, but some TOs refused to agree.
The commission said SPP may withhold the settlement revenues from them, but the RTO must pay interest on any amounts withheld once the allocation is final. “SPP has not provided justification for it to withhold the settlement revenues without any interest,” FERC said.
FERC Order Allows SPP to Reduce ARRs
FERC last week accepted an SPP compliance filing that reduces the number of auction revenue rights made available in its annual allocation process (ER16-13).
SPP filed proposed Tariff revisions last October reducing the percentage of available transmission capability used to determine simultaneous feasibility.
FERC responded by asking SPP to modify section 7.3 of Attachment AE in its Tariff, specifying that transmission providers make available 60% of their transmission system capability for the fall, winter and spring seasons (October-May) during the annual ARR allocation process.
The RTO proposed corresponding revisions to the attachment removing references to assumed system capability for June-September to reduce potential ambiguity in the ARR settlement calculations during the annual transmission-congestion rights auction.
SPP to Bill Tri-County, Refund Tx Customers
FERC directed SPP to bill Tri-County Electric Cooperative for the co-op’s annual transmission revenue requirement (ATRR) with interest and to refund the amount to customers affected during a 10 1/2-month period in 2012-2013 (ER12-959).
The action corrects a “legal error” made by the commission in a 2012 docket that concluded with a 2014 affirmative order. Xcel Energy Services petitioned the D.C. Circuit Court of Appeals to review the decision, arguing that the rates at issue were SPP’s rates, not Tri-County’s.
The D.C. Circuit held that FERC failed to justify its decision to allow SPP’s filing to go into effect without a refund commitment by Tri-County, “thus failing to ensure that SPP’s rates would be just and reasonable.” The court found the commission “misapprehended its remedial powers and thus arbitrarily declined to weigh the equities underlying Xcel’s request for retroactive relief.”
FERC said it was remedying the error by directing SPP to bill Tri-County for the amounts of the co-op’s revenue requirement that SPP collected from ratepayers between April 1, 2012, and Feb. 21, 2013, with interest. It also directed SPP to make refunds to ratepayers once it received payment from Tri-County.
The proceeding began on February 2012, when SPP filed Tariff revisions to implement a formula rate in calculating Tri-County’s ATRR as a nonpublic utility participating transmission-owning member in the pricing zone of Xcel’s Southwestern Public Service.
The commission admitted it accepted SPP’s filing and set it for settlement hearings “without following its policy of accepting a rate filing to take effect pending the outcome” of further procedures when Tri-County agreed to refund the difference between the as-filed rate and FERC’s final approved rate.
Tri-County is a non-jurisdictional not-for-profit distribution cooperative with headquarters in Hooker, Okla. It serves approximately 23,000 customers in Oklahoma, Kansas, Texas, Colorado and New Mexico.
Western Farmers’ 10.87% ROE Approved
The commission accepted revisions to SPP’s Tariff adopting a formula rate for Western Farmers Electric Cooperative’s transmission service, while also sending the case to a settlement judge to address questions regarding the co-op’s return on equity and depreciation rates.
FERC’s order approved Western Farmers’ request for a return on equity of 10.87%, including a 50-basis-point adder for participation in SPP on top of its 10.37% base ROE (ER16-1774).
The commission noted that while Western Farmers is not within its jurisdiction under Section 205 of the Federal Power Act, it was “appropriate to apply the just and reasonable standard … to SPP’s proposed rates filed on behalf of Western Farmers.” That allows the utility to receive the same overall ROE “as that used by the applicable transmission zone’s dominant transmission owner.”
The commission said the case would be more appropriately addressed in settlement proceedings because Western Farmers’ proposed ROE is based on an average of other SPP transmission owner ROEs, which is not a FERC-approved methodology. FERC also said the utility proposed unsupported depreciation rates and failed to ensure wholesale customers will not be charged for capitalized construction funds and work in progress.
Western Farmers is a rural electric cooperative that provides wholesale power to 21 distribution cooperative member-owners in Oklahoma and New Mexico, as well as Altus Air Force Base.
NPPD Allowed to Terminate QF Contracts
The commission largely granted the Nebraska Public Power District’s application to terminate a requirement that it enter into new obligations or contracts with qualifying facilities with net capacities of more than 20 MW (QM16-1).
FERC said it terminated the mandatory purchase requirement because QFs in NPPD’s territory have “nondiscriminatory access” to wholesale markets. NPPD had argued that as an SPP member, it had satisfied its regulatory requirements under the Public Utility Regulatory Policies Act and was not subject to the commission’s authority under the FPA.
The order made an exception for NextEra Energy’s Cottonwood QF, which initiated a proceeding before NPPD’s board of directors “that may result in a legally enforceable obligation.” The commission grandfathered the Cottonwood contract because the facility sent a purchase request to NPPD last November, before the utility’s original Feb. 12 application to FERC. It found Cottonwood’s letter had established “a contract or legally enforceable obligation.”
NextEra was among a handful of SPP members and QFs that intervened, saying it had three self-certified QFs in NPPD’s service territory. NextEra did not challenge NPPD’s assertion it had satisfied PURPA’s requirements, but it said NPPD failed to acknowledge two letters seeking the utility’s purchase of the output from two of its QFs.
FERC found that the second letter, sent by Sholes Wind on the same day NPPD filed with the commission, was not filed prior to Feb. 12, and thus was not grandfathered.
New York’s proposal to subsidize upstate nuclear power plants was blasted as a corporate giveaway and embraced as an economic lifeline and necessity to reduce carbon emissions in comments filed last week with regulators (15-E-0302).
Although it was the first time commenters had the opportunity to respond to the projected price tag of the subsidy, the arguments were familiar.
The subsidy was proposed earlier this year as part of the larger Clean Energy Standard. The original proposal pegged the nuclear subsidy as the difference between the average wholesale price of electricity and the operating cost of the nuclear plant. (See New York Would Require Nuclear Power Mandate, Subsidy.)
On July 8, the PSC staff released what it called a “responsive proposal” that calculated ZECs based on estimates of the social cost of carbon. The PSC said that would be $17.48/MWh for qualifying nuclear power generators in the first two years of the 12-year program, or about $965 million.
A coalition of environmental groups — including the Alliance for a Green Economy, the Council on Intelligent Energy & Conservation Policy, the Nuclear Information and Resource Service and the Sierra Club’s Atlantic Chapter — continued its opposition.
“After claiming the nuclear tier would cost only $270 million over 12 years, the new ‘responsive proposal’ outlined a plan that will cost nearly $1 billion in just the first two years, with costs escalating to total approximately $7.6 billion. The program will likely cost more than $10 billion if Indian Point gets included,” they wrote.
The Brattle Group, which had done a study last year for New York labor groups, said the subsidy is cost-effective, estimating that electricity costs would rise by an average of $1.7 billion a year between 2015 and 2024 without the nuclear plants. “Although customers would pay for ZECs, they would avoid a power price increase that is larger than the ZEC cost. This means that customers actually pay less overall for power than if the upstate nuclear plants were to shut down.”
Upstate Energy Jobs, a coalition of municipal, business, labor, education and economic development leaders, said it supports the ZECs to keep the plants operating during the transition to clean sources. “Furthermore, renewable energy sources are not being constructed at a pace that makes replacing nuclear power with renewable power a realistic approach at this time.”
Towns and legislative members from western New York also focused on the plants’ economic impact. Comments from the Town of Scriba, which is the site of three nuclear plants, Nine Mile Point 1 and 2 and James A. FitzPatrick, were typical.
“More than any other community in New York state, we are most affected by the potential closure of these facilities should a reasonable and workable solution to the current financial difficulties facing our upstate nuclear-powered electric generators not be realized in a timely manner.”
Fitzpatrick Nuclear Plant Source Entergy
Exelon is the owner of three nuclear power plants on Lake Ontario, with two in Scriba, and is in negotiations to acquire a fourth. (See Entergy in Talks to Sell FitzPatrick to Exelon.) FitzPatrick has been scheduled to close early next year by its current owner, Entergy. Exelon said it would close Nine Mile Point 1 and R.E. Ginna early next year if a contract is not in place by the end of September.
“Time is of the essence,” Entergy reiterated in its comments.
A group representing large commercial and industrial customers complained that the July 8 proposal is an entirely new formula that is considerably more expensive than what was discussed in earlier proceedings. “In New York’s apparent haste to appease the owners of selected nuclear generation facilities to ensure the continued operation of those facilities, customers are being exposed to potentially 12 years of artificially inflated and excessive subsidy obligations,” it wrote.
Likewise, the National Energy Marketers Association said the proposal interferes with the development of the retail market. “The proposed purchasing and pricing mechanism under which [load-serving entities] will be required to purchase ZECs will have an adverse impact” on energy service companies, it said.
NYISO emphasized the environmental and reliability attributes of the plants. “The state’s nuclear power stations are non-emitting resources that already contribute significantly to the state’s production of clean energy and supply 30% of New York’s energy requirements.”
The Pace Energy and Climate Center supports the ZEC program by emphasizing it as a temporary bridge until renewable energy is built at scale, a point also emphasized by Exelon’s Constellation Energy Nuclear Group.
“While the long-term goal for New York should be to replace the state’s existing nuclear fleet with renewables that are additional to the CES target, over the next 12 years, the governor’s plan to support the state’s nuclear fleet will ensure that New York is able to achieve its carbon emissions targets while making rapid progress towards the CES goal,” Pace wrote.
The American Petroleum Institute proposed an expansive definition of credits for carbon reduction. “The NYPSC must create a level playing field by making emissions credits available to all technologies and energy sources that can reduce net GHG emissions from the electricity sector, including … energy efficiency measures, and other forms of electricity generation that can help achieve compliance with state emission reduction goals, such as natural gas, [combined heat and power], biomass, and waste heat power,” it said.
The PSC could act on the CES at its next regular meeting on Aug. 1.
CAISO last week provided an explanation of its decision to increase regulation requirements in response to the growing variability on its system.
The ISO’s Department of Market Monitoring last month called attention to the sharp rise in costs from the requirements, prompting the California Energy Commission to ask the ISO to justify the move. (See CAISO Regulation Costs Quadruple as Price, Procurement Jump.)
During a Market Performance and Planning Forum last week, CAISO said it doubled its frequency regulation service requirement from late February to mid-June in response to recurring short-term generation forecasting errors stemming from variable wind and solar resources during late winter and spring.
CAISO’s regulation procurement ramped up sharply ahead of spring, but was backed down with the more predictable summer weather patterns.
The forecasting problem is mostly isolated to spring, when high renewable output often coincides with periods of low loads in California. At the same time, weather patterns tend to be more erratic, often making it especially difficult to predict renewable output on a moment-to-moment basis.
Regulation prices more than doubled shortly after the ISO increased its daily regulation procurement from 400 MW or less to as much as 800 MW in late February. Daily payments to regulation service providers surged from $100,000 to more than $400,000, the ISO’s Monitor found last month.
The ISO rolled back regulation requirements to previous levels for summer because of more predictable weather patterns.
Further compounding the spring forecasting issue is the increasing adoption of residential rooftop solar, which is subject to the same variability as utility-scale projects. The ISO estimates it has nearly 5,000 MW in rooftop solar in its balancing area, with new installations added daily. Variability in behind-the-meter rooftop output complicates matters by causing loads to skew from forecasts depending on whether the sun is shining.
The problem “happens more in the off-season — with more of the clouds coming in,” said Amber Motley, CAISO short-term forecasting manager. “Timing and forecasting of [generation] ramps are very difficult. Forecasting cloud coverage is difficult.”
Variable wind production can also be a factor, with cold fronts making it difficult to predict the timing of wind ramps and changes in wind direction causing intermittency.
Clyde Loutan, ISO senior advisor for renewable energy integration, said weather changes can occur too quickly to incorporate revised forecasts into the real-time market run. He also pointed out that forecasting errors are not covered under the ISO’s real-time contingency dispatch process, which sets aside generation to allow the system to recover from major disturbances.
“So you have to rely on regulation,” Loutan said.
“Seems like it’s more a failure of the forecast,” said Dan Williams, CAISO markets analyst at Portland General Electric. “And that should be changed by changing the market rather than rolling it into regulation.”
Loutan countered that he didn’t know of any forecaster that could reflect the intermittency in the five-minute market.
“When you think about how these markets were designed, they were really designed for conventional units,” he said.
Loutan also pointed to a clear financial incentive driving the ISO’s increased requirement.
“Back in January we had some pretty bad days when we didn’t control the frequency well enough,” he said. “For 11 hours, we had a hard time controlling the system. We found out that we were running out of regulation.”
If the condition had persisted longer than 30 consecutive minutes, the ISO would have been subject to as much as $1 million in NERC penalties, he said.
Carolyn Kehrein, principal consultant for the Energy Users Forum, suggested that increased regulation costs should be allocated to intermittent resources if the forecasting problem continued and the ISO didn’t develop new tools to deal with it. She said increased costs for intermittency should encourage the “right kind” of renewable development, such as geothermal.
Wei Zhou, senior project manager with Southern California Edison, agreed with applying the cost-causation principle to the problem.
“This is something that we’re looking at long-term,” said Loutan, referring to the forecasting issue at large. “But for now we just wanted to explain why we increased our regulation procurement.”
Staff from ERCOT and SPP began discussions last week to determine how to work together on Lubbock Power & Light’s planned move to the ERCOT grid.
The grid operators conducted a staff-only call July 21 at the behest of the Public Utility Commission of Texas, which has bifurcated LP&L’s application to join ERCOT into two cases: one involving the move itself and the other involving a cost-benefit analysis of on ratepayers. (See Texas PUC Takes Slow Approach with LP&L Integration.)
PUC Chair Donna Nelson last week filed a memo describing the information the commission will be looking for from the grid operators’ studies on LP&L’s migration (Docket No. 45633).
“A joint study between ERCOT and SPP on the tangible costs and benefits could mitigate the issues that arise when studies are conducted by different parties,” Nelson wrote.
Commissioner Ken Anderson agreed with Nelson during the PUC’s July 20 open meeting, saying it is important the two entities know how they’re going to proceed.
“The question I will have for SPP and ERCOT … if they can agree on the same method to analyze not just the options of how to, but the more important one of the costs and benefits,” he said. “Then, finally, the costs that stranded ratepayers in SPP would have as a result, if any. I’m not conceding there are [some] now, but how do you think about the impact on Texas ratepayers outside of Lubbock?”
“In my mind, the key component here is so you can interpret the information, and not having a situation where you’re comparing apples to oranges,” Warren Lasher, ERCOT’s director of system planning, told Nelson. “I don’t feel at this time we have to do a joint study, but what we can do is ensure you have the information you can translate between the two studies.”
SPP’s principal regulatory analyst, Sam Loudenslager, told the PUC the RTO staffs would file a preliminary draft study scope before the commission’s next open meeting on Aug. 18.
LP&L announced last September it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. An ERCOT study completed in June indicated it will cost $364 million and take 141 miles of new 345-kV right of way to incorporate LP&L into ERCOT. (See “LP&L Integration Could Unlock More Panhandle Wind Energy, ERCOT Board of Directors Briefs.)
Nelson and her fellow commissioners are also concerned about other companies that may be looking to join ERCOT. Rayburn Country Electric Cooperative, an ERCOT-turned-SPP member with 85% of its load in the Texas grid, has asked the ISO to conduct an integration study as it considers rejoining.
“I’m inclined to think we deal with Lubbock as a one-off,” Anderson said. “It’s a much smaller deal for Rayburn. The question becomes the precedent” it sets.
The commissioners agreed to discuss a rulemaking for new ERCOT members at its next meeting.
“I favor initiating the production of pertinent studies now while concurrently determining whether we need a rule for a clear framework for similar requests in the future,” Nelson said in her memo.
Nelson also stressed the importance of maintaining ERCOT’s independence from federal oversight. “Of import to us all, we need to ensure that Lubbock’s move into ERCOT will not invoke federal jurisdiction over ERCOT,” she said.
In her memo, Nelson provided additional issues she felt were “specific to the matter at issue:”
The impact to the ERCOT and SPP systems’ reliability and operational costs;
The costs of any facilities that would be required or that could be avoided on the ERCOT and SPP systems;
The benefits or challenges that the subject loads would provide or impose on each system;
The impact on wholesale and retail customers, markets and market participants;
Whether LP&L’s status as a municipal utility should be considered in the cost-benefit analysis; and
The length of time the no-harm standard — making LP&L liable for added costs passed on to customers — should be applied to the utility for its admission to ERCOT.
Nelson said she would also like to see analysis of alternative or gradual paths for entry into ERCOT “that are prudent for us to consider” under the cost-benefit analysis.
A federal judge in Massachusetts on Thursday ordered a full civil proceeding, including a jury trial if necessary, in FERC’s enforcement of a $5 million fine for alleged market manipulation by a power generator (IN15-4).
U.S. District Judge Mark G. Mastroianni said the proceeding is necessary to preserve the due process rights of Maxim Power, which the commission said billed ISO-NE for oil-fired generation when the company was actually burning cheaper natural gas at one of its plants. (See Maxim to FERC: Prosecute or Drop Probe.)
Mastroianni said Maxim is entitled to a full de novo review, allowing it the full range of discovery, rather than be limited to reviewing FERC’s evidence.
“While respondents were free to submit evidence and responsive arguments, they were unable to seek discovery, depose witnesses interviewed by FERC, gain any insight into the presentation of the case made by FERC’s enforcement staff to the commissioners during the investigative phase or present their own witnesses,” Mastroianni wrote.
The U.S. 5th Circuit Court of Appeals has stayed implementation of an EPA-imposed regional haze plan for Texas and rejected the agency’s motion to move the case to the D.C. Circuit Court of Appeals, agreeing with petitioners who said they “could suffer irreparable injury in the absence of a stay.”
The court was unconvinced by EPA, which said a lack of a haze plan would harm the public and visibility at national parks. The agency itself acknowledged that the federal implementation plan would not reduce emissions for at least three years, the court noted. ERCOT also expressed reliability concerns over the plan.
EPA rejected Texas’ regional haze plan as insufficient. The federal plan sets sulfur dioxide emission limits on eight coal-fired plants in the state.
The Bureau of Ocean Energy Management will auction drilling rights for nearly 24 million acres in the Gulf of Mexico via live streaming on Aug. 24, the first time the agency has conducted a lease sale online.
“Making government data immediately available is a valuable resource for taxpayers, both in terms of dollars and cents but also in efficiency,” BOEM Director Abigail Ross Hopper said. “Through the use of technology, we can deliver our lease sale information in a much more effective and accessible way to a much wider audience.”
It will be the final lease sale in the Western Planning Area under the Obama administration.
The U.S. moved up to 8th from 13th in a study of energy efficiency among nations. The country still lags behind Germany, Italy and Japan (tied for second), France, the U.K., China, Spain and South Korea, according to a report issued by the American Council for an Energy Efficient Economy.
According to the report, 23 countries account for 75% of the energy consumed on Earth. The U.S. was able to boost its ranking because of improvements in energy use per dollar of gross domestic product, as well as a change in the way energy policies are weighted in the study.
“Despite its leadership on a number of policies, the United States falls behind most of the [European Union] countries on our list in addition to China and Japan,” according to the report. “The United States still has no binding energy savings goals, unlike Germany, France, Japan and other countries, which have a national energy conservation plan in place.”
Former Employee: SoCalEd to Blame for San Onofre Leak
A report by a former engineer employed by Southern California Edison concluded that workers ran the San Onofre nuclear station near San Diego at higher temperatures and pressures than allowed, eventually causing a radiation leak that forced the plant to be permanently shut down.
Vinod Arora based his report on Nuclear Regulatory Commission documents obtained through a Freedom of Information Act request. Arora is still seeking daily control room logs from the company. “If those logs have not been destroyed, they will show immediately whether or not Edison risked the lives of 8.5 million Southern Californians by redlining the Unit 3 generators,” he said.
The company blames Mitsubishi Heavy Industries, which designed the steam generators at the plant for the problems.
EPA Administrator Gina McCarthy said she is confident the U.S. and other countries will be able to reach an agreement on a rule limiting the release of hydrofluorocarbons (HFCs) before the end of the year. McCarthy, who is leading a U.S. delegation that includes Secretary of State John Kerry, said she has seen clear signs of progress.
Negotiators from about 200 countries are in the midst of meetings in Vienna under the Montreal Protocol, a 1987 treaty that limited the emission of hydrochlorofluorocarbons (HCFCs), which severely damage the ozone layer.
HFCs, potent greenhouse gases used as refrigerants that were developed as alternatives to HCFCs, do not fall under the original agreement, as they do not affect the ozone layer. A rule resulting from the meetings taking place would amend the Montreal treaty to include the gases. A final deal is expected to be reached in October at a meeting in Rwanda.
White House Pledges $4.5B For EV Charging Stations
The Obama administration announced it is freeing up $4.5 billion in Energy Department loan guarantees for commercial electric vehicle charging stations.
The funds are part of the administration’s broader initiative to accelerate the use of EVs. It will also designate and develop “charging corridors” to form of a national network of stations by 2020.
The initiative to provide more stations “serves the goal of providing consumers with more comfort that they will be able to move across regions and across the country in their electric vehicles,” a White House official said.
The U.S. Navy and Dominion Virginia Power plan to build a 21-MW solar facility at the Navy’s Oceana Naval Air Station near Norfolk, according to the Solar Energy Industry Association.
Dominion expects the plant to be operational by the end of next year. Under the agreement, Dominion will own and operate the facility for 37 years in exchange for electrical upgrades at the base.
ISO-NE said that prices and consumption remained low throughout New England in June.
The six-state region’s average real-time, monthly wholesale power price during June was $21.24/MWh, up 8.3% from June 2015’s average price of $19.61/MWh, but lower than May’s $21.29, which held the record for the third-lowest price since 2003 for only a month.
Total energy consumption during June was at the second-lowest level of any June since 2000, likely because of continued mild weather, the RTO said. The lowest average monthly price ever is $17.20/MWh, set in March.
The Public Utilities Commission has opened a penalty case against Southern California Edison over a series of underground electrical fires that caused explosions and cut power to thousands of customers in Long Beach last July.
The proceeding will determine whether the utility violated any regulations and provided an adequate emergency response to the events, which left some customers without service for as many as five days and caused explosions strong enough to blow manhole covers into the air.
The Utility Regulatory Commission sanctioned a 6% electric base rate hike for Northern Indiana Public Service Co. last week, the first change to base rates since 2011.
NIPSCO said it needs the money to pay for higher expenses and service upgrades. The utility said a typical residential customer will pay $5.70 more per month.
The base rate agreement was previously struck by the Office of Utility Consumer Counselor, NIPSCO’s industrial customers, a coalition of eight municipalities and the United Steelworkers in February. Consumer Counselor David Stippler called the agreement “a fair resolution for NIPSCO’s residential and commercial customers.”
Court Nixes Utility’s Plan to Buy Power from Biomass-Burning Facility
A state Court of Appeals panel has struck down ecoPower Generation’s contract to sell electricity to Kentucky Power.
The court said there was no evidence that ecoPower’s biomass-burning plant would result in an economic benefit to customers or the region. The court cited testimony that the agreement would result in an increase of up to 7% in the average monthly residential bill in the first year and a jump of up to 13% in later years.
The ruling puts the future of the plant, which would burn wood and sawdust to generate enough electricity for 30,000 homes, into doubt. Kentucky Power is reviewing the ruling before it decides whether to appeal, a spokesperson said.
Delmarva Power, now under Exelon ownership, is asking regulators to approve a $66.2 million electric rate base increase to pay for reliability improvements and smart grid upgrades conducted over the past four years. The increase would boost a typical monthly bill by 14.5%.
If approved by the Public Service Commission, the rate adjustment would translate to a $21.42 increase on the monthly bill of residential customers using 1 MWh, to $168.64 a month.
Delmarva said it has spent more than $330 million on improvements in the state since 2012. Its last rate-increase request was in 2013.
Opponents of a proposed natural gas pipeline loop through a state forest want to block a water-quality approval certificate issued June 30.
A coalition of environmentalists and landowners appealed the state Department of Environmental Protection’s approval of Kinder Morgan’s 4-mile Connecticut Expansion Project with the agency. The final decision would come from DEP Commissioner Martin Suuberg.
Developer Greycliff Wind Prime’s proposed 25-MW wind farm is unlikely to move forward following the Public Service Commission’s decision to set its wholesale price to NorthWestern Energy at $45.49/MWh, about 16% lower than the price it says it needs to make a profit.
“It’s not a rate that works. It’s also not a rate that’s realistic,” said Steve Tyrell, a Greycliff stakeholder. Developers said they needed a price in the mid-$50s, which would have been similar to the rate for another NorthWestern renewable energy source.
Renewable energy projects are on a two-month losing streak with the PSC. The commission in June pulled the plug on guaranteed rates for small solar projects at the request of NorthWestern.
Peppermill Casinos Seeks to Sever Ties with NV Energy
Reno-based Peppermill Casinos became the third hotel casino operator in recent months to notify state regulators that it intends to leave NV Energy and acquire electricity from other sources.
The move will entail a costly exit fee. Las Vegas Sands reversed its decision to leave the utility after the Public Utilities Commission determined the company would have to pay $24 million to do so.
Peppermill has invested $9.7 million in onsite geothermal generation. “We are committed to continuing that investment in responsible and renewable energy sources,” a company executive said. Wynn Resorts and MGM Resorts International have also announced their intentions to leave NV Energy.
Regulators completed a two-day evidentiary hearing examining Duke Energy’s $4.9 billion acquisition of Piedmont Natural Gas, moving the merger toward a decision by the Utilities Commission as early as October.
The commission’s staff supports the merger, the costs of which will be charged to shareholders, not customers, the companies said.
Under the deal, Duke will give Piedmont’s customers in the state a $10 million break on bills over two years. It also will donate $17.5 million to charity over four years and earmark $7.5 million to help low-income customers and support community job training.
Duke Energy has asked a federal judge to block the testimony of a state toxicologist in a lawsuit, filed against the utility concerning its handling of coal ash, from being made public.
The company argued that the testimony of Dr. Kenneth Rudo, of the epidemiology branch of the state Department of Health and Human Services, about his views on the toxicity of coal ash and its effect on drinking water supplies is “largely hearsay” and would prevent the company from getting a fair hearing. The lawsuit was filed by environmental organizations.
Residents have received mixed messages from state officials about the safety of their drinking water, who were told to avoid using it last month after receiving assurances that it was safe. Testimony transcripts already released by the plaintiffs show disagreement among state scientists about the advice to give residents.
A Renewable Energy Systems Americas subsidiary filed an application with the Public Service Commission last week for what would be the largest wind farm in the state. Glacier Ridge Wind Farm proposed a 300-MW project with nearly 100 turbines in Barnes County.
Glacier Ridge aims to start construction in November and complete work in 2019.
Regulators Approve Opt-outFees for PSO Smart Meters
The Corporation Commission approved a plan allowing Public Service Company of Oklahoma to charge a $28 monthly fee to customers who opt out of installing a smart meter. The three-person commission unanimously approved the fee. Customers will also need to pay a one-time fee of $71, which will increase to $110 next year.
PSO originally requested a $28 monthly fee and one-time fees between $183 and $261. Its customers already are paying $3.11 monthly fees for smart meter installation, part of a $133 million rate case settlement the commission approved in April 2015.
Commission Chairman Bob Anthony said estimating costs is tricky because the commission is starting from scratch on the opt-out program. “We haven’t done this before; we don’t know if there’s going to be 200, 500 or 1,000 people [who] sign up for this program,” Anthony said.
Fire Damage to GRDA Plant Could Reach as Much as $200M
The Grand River Dam Authority says its costs could reach $200 million to recover from a July 1 fire at its main generating facility in Chouteau. Officials from the state-owned utility say the final bill will depend on the cost of rebuilding the larger of the two coal-fired units affected.
The utility believes the fire was started by a lightning strike that knocked out the unit’s cooling pumps, causing it to overheat and creating a friction fire. The fire spread to the roof of the building and caused the other coal-fired generator, Unit 1, to automatically shut down.
Assessing the damage to Unit 2 and the building that houses both units is expected to take about a month. GRDA recently completed an $86 million environmental upgrade to the 30-year-old Unit 2.
FE Subsidiary Starts Work on 5-Year Grid Improvement Plan
West Penn Power, a subsidiary of FirstEnergy, is starting work on $17 million of grid improvement projects to enhance reliability for its 720,000 customers.
The projects are part of the company’s five-year infrastructure improvement plan approved earlier this year by the Public Utility Commission.
The long-term plan calls for $88 million to be spent through 2020 on upgrades, including installing protective devices on wires and poles, rebuilding transmission lines and installing automated and remote control devices.
Gov. Gina Raimondo offered little comfort to residents opposed to a 1,000-MW natural gas plant in Burrillville, where she said at a community meeting that gas-fired generators are needed to bridge the gap until clean generation is built at a larger scale.
“I’m for green energy and moving as fast as we possibly can from fossil fuels and towards cleaner sources of energy,” she said. “But I’m also for keeping energy prices as low as possible for the people of Rhode Island.” Raimondo has previously said that the $700 million plant proposed by Invenergy would create jobs and moderate electricity prices.
“What I need to do as governor is balance the interests of all the people,” she said. “In the near term, natural gas is a piece of that puzzle.” This final comment drew boos from those in attendance. Raimondo then had to fend off criticism from speakers.
As expected, SPP’s first summer since the Integrated System joined its system last year has resulted in a new record for peak load, as well as the RTO’s first two peaks above 50,000 MW.
The RTO recorded a peak load of 50,083 MW at 4:35 p.m. July 20, surpassing that record the next day at 4:47 p.m. with 50,622 MW. The previous record of 48,323 MW was set in June.
The record peaks were not a surprise, given the addition of the Integrated System’s 5,000 MW of added peak demand and the oppressive heat wave in the Great Plains. Bruce Rew, SPP’s vice president of operations, told the Regional State Committee last week the RTO will “likely continue to see increases in peak numbers, primarily driven by the addition of new members.”
The Bureau of Ocean Energy Management will auction drilling rights for nearly 24 million acres in the Gulf of Mexico via live streaming on Aug. 24, the first time the agency has conducted a lease sale online.
The U.S. moved up to 8th from 13th in a study of energy efficiency among nations. The country still lags behind Germany, Italy and Japan (tied for second), France, the U.K., China, Spain and South Korea, according to a 
A report by a former engineer employed by Southern California Edison concluded that workers ran the San Onofre nuclear station near San Diego at higher temperatures and pressures than allowed, eventually causing a radiation leak that forced the plant to be permanently shut down.
The U.S. Navy and Dominion Virginia Power plan to build a 21-MW solar facility at the Navy’s Oceana Naval Air Station near Norfolk, according to the Solar Energy Industry Association.
ISO-NE said that prices and consumption remained low throughout New England in June.
The Public Utilities Commission has opened a penalty case against Southern California Edison over a series of underground electrical fires that caused explosions and cut power to thousands of customers in Long Beach last July.
The Utility Regulatory Commission sanctioned a 6% electric base rate hike for Northern Indiana Public Service Co. last week, the first change to base rates since 2011.
A state Court of Appeals panel has struck down ecoPower Generation’s contract to sell electricity to Kentucky Power.
Developer Greycliff Wind Prime’s proposed 25-MW wind farm is unlikely to move forward following the Public Service Commission’s decision to set its wholesale price to NorthWestern Energy at $45.49/MWh, about 16% lower than the price it says it needs to make a profit.
Reno-based Peppermill Casinos became the third hotel casino operator in recent months to notify state regulators that it intends to leave NV Energy and acquire electricity from other sources.
A Renewable Energy Systems Americas subsidiary filed an application with the Public Service Commission last week for what would be the largest wind farm in the state. Glacier Ridge Wind Farm proposed a 300-MW project with nearly 100 turbines in Barnes County.
The Grand River Dam Authority says its costs could reach $200 million to recover from a July 1 fire at its main generating facility in Chouteau. Officials from the state-owned utility say the final bill will depend on the cost of rebuilding the larger of the two coal-fired units affected.
West Penn Power, a subsidiary of FirstEnergy, is starting work on $17 million of grid improvement projects to enhance reliability for its 720,000 customers.
