FERC on Friday approved an amendment to SPP’s bylaws clarifying that the RTO should not credit assessments for transmission service over and above the amount of members’ monthly administrative fee.
But the commission said the RTO improperly clawed back overpayments last year based on its reinterpretation of its bylaws before the rules were officially changed, ordering the RTO to pay $1.6 million in refunds (ER16-829).
SPP collects its administrative costs through a monthly assessment applied to load eligible to take network service under its Tariff (Schedule 1-A fees). Members receive a credit against the monthly assessment for fees paid for serving their load with network or point-to-point transmission service.
Between 2003 and 2015, the RTO had been making credits that sometimes exceeded the 1-A fees, with the RTO providing credits against other portions of the customers’ transmission settlement statements. The excessive credits resulted in a 1% undercollection of its administrative fees annually, forcing SPP to charge a higher administrative rate in the subsequent years.
In March 2015, SPP staff reinterpreted its bylaws and capped the credits. In December, the Board of Directors approved a revision of section 8.4 of the bylaws to clarify the new practice.
FERC approved the new crediting policy effective March 30, 2016, but denied SPP’s request for a waiver allowing the RTO to apply it retroactively.
As a result, the commission ordered SPP to provide refunds within 30 days for credits it denied last year under its new interpretation. The ruling was a victory for 13 SPP members who received credits in excess of their monthly assessments during 2014. Two members who filed protests, Kansas City Power and Light and Nebraska Public Power District, will receive the majority of the refunds, a combined $1.2 million as of December.
DETROIT — Four industry executives and a state regulator shared their views on distributed generation, resource adequacy and aging infrastructure during a stakeholder panel at the MISO Annual Meeting last week.
Robert Gee, of Gee Strategies Group, moderated.
Melody Birmingham-Byrd of Duke Energy Indiana called distributed energy resources an “inevitability” and said her company is embracing the change with “heavy involvement” in research and projects.
However, she said designing a DER rate structure remains a concern. “We want to make sure those who can afford distributed resources aren’t doing it on the backs of those that can’t,” she said.
Teresa Mogensen, senior vice president of transmission at Xcel Energy, said the grid “is a long, long way from being dead” and will continue to play a role even with greater use of distributed generation.
“We do have customers that have disconnected from the grid, and if they’ve done that, more power to them,” said DTE Electric President and COO Trevor Lauer. He said his company will be aided in its transition to DER by new, younger workers: DTE Energy will turn over 50% of its workforce over the next seven years, he said.
Jennifer Vosburg, senior vice president of NRG Energy’s Gulf Coast region, said customers “aren’t waiting around: The utility of the future is here. Our concern is, can the markets keep up, can the regulation keep up, can it be integrated into the market system?”
Michigan Public Service Commission Chairman Sally Talberg said she didn’t know how soon distributed resources would permeate the grid. “I have a National Geographic from 1983 that says solar is the way of the future,” she joked.
Resource Adequacy Concerns
All of the speakers expressed concerns over MISO’s ability to attract new generation to replace retiring plants.
“Right now, it’s hard to see how an independent power producer [without] a power purchase agreement could build new generation,” Lauer said.
Vosburg said MISO hasn’t implemented anything to “trigger new investment.”
The panel also addressed the growth of natural gas and its history of price volatility.
“Who would have thought seven years ago that there would be such a fundamental change in electric generation with fracking and natural gas use?” Lauer said. “I think price volatility is going to be there, but I think the larger concern is infrastructure and gas storage.”
Talberg agreed and said pumping gas through pipelines in Michigan can be “high-risk” since some pipelines are “vintage.”
The panel generally agreed that the Clean Power Plan stay isn’t going to slow progress on emission reductions.
“Our concern is the rate and pace of carbon emission [reductions], not that we’re going down that path,” Birmingham-Byrd said. “What Duke Energy is trying to do while [we] retire coal plants is to have a more diverse generation portfolio.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
PJM Manuals (9:10-10:00)
Members will be asked to endorse the following manual changes:
Manual 7: Protection Standards. Clarifications were recommended by the Relay Subcommittee as part of its biennial review of the manual.
Manual 10: Pre-Scheduling Operations. Changes make clear that reporting rules for all outages apply to both capacity and energy resources.
Manual 14B: PJM Region Transmission Planning Process. Updates light load and winter peak reliability analyses to align with current practices, among other updates.
Manual 15: Cost Development Guidelines. Clarifications are the result of a periodic review. Adds Tariff-approved language regarding pumped storage hydro units.
Manual 18: PJM Capacity Market. Changes are the result of a periodic review; conforming changes relate to Capacity Performance and the “deploy all resources” action.
The committee will be asked to endorse changes to make the parameter-limited schedule exception process more flexible. (See “More Flexible Parameter Limited Exception Process Approved,” PJM Market Implementation Committee Briefs.)
Members will be asked to elect Gary Greiner of Public Service Enterprise Group as a Transmission Owner sector representative. He will take the place of PSEG’s Frank Czigler, who has left the company.
AUSTIN, Texas — To address the Defense Department’s frustrations over Texas’ lack of regulation for siting new generation, the governor’s office is working with ERCOT to require notifying the department of proposed projects that might impact military operations.
DeAnn Walker, a senior policy adviser in Gov. Greg Abbott’s administration, told a Gulf Coast Power Association luncheon audience that she’s been working on the issue for nine months. Military issues are a top priority for Abbott, she said.
The Pentagon’s main concerns have been wind turbines disrupting radar signals and solar panels causing glare for pilots. Used to working with states who have control over siting facilities, military officials have been frustrated with Texas’ system, which lacks any state-level oversight. “The military claimed there were times when the first time they knew about a wind turbine farm going up near their facility was when they started seeing the turbines built,” she said.
Walker said concerns have been raised over projects planned around naval air stations in Corpus Christi and Kingsville. She knew of only one generation project canceled because of a conflict with military operations.
Walker worked with ERCOT to develop PGRR 47, which was presented in May. The change to ERCOT’s Planning Guide would require developers seeking interconnection approval to report on the status of reviews by the Pentagon and the Federal Aviation Administration.
A luncheon attendee pointed out that the military already receives notification about projects from FAA, which can occur much sooner than the interconnection application.
In exchange for its cooperation, the state has asked the Defense Department to provide color-coded maps that show where developers might run afoul of military siting restrictions, Walker said. The maps would be of all military operating areas in the state and be marked green (where there are no restrictions), yellow (where they could work together toward a solution) and red (where the military would oppose any development). Another attendee said the maps already exist on FAA’s website.
Walker said Abbott is adamant about winning approval of the change and asked that anyone with concerns address them with her directly.
Although the lack of siting regulation has caused tensions in Texas, the Defense Department has worked cooperatively with the power industry, becoming early advocates of renewables and microgrids.
At a FERC technical conference on reliability earlier this month, Chris Murray of the Navy’s Renewable Energy Program Office invited transmission and generation projects onto naval facilities. “If there is land on our base that you think makes sense, let us know. And more often than not, that land is going to be behind a secure perimeter with guards, which also can be good for a critical asset,” he said.
DETROIT — MISO expects the use of technologies such as energy storage, synchrophasors and HVDC lines to increase, Executive Vice President of Transmission and Technology Clair Moeller told the Board of Directors at its System Planning Committee meeting last week.
“As we do modeling into the out years … we see a substantial shift in the footprint away from coal — and that’s expected. But how the rest of the mix [develops] plays an important role,” Moeller said. “It’s a pretty interesting time in terms of how the portfolio might shift.”
Synchrophasors, which provide real-time transmission data, can answer whether “you can safely take the system to its physical limits to completely squeeze all you can out of the grid.” Moeller said. “This is the electric system’s introduction into big data.”
“How much [capacity] is in [the transmission system]? Because you know it’s there,” board member Paul Bonavia said. “This is a lot of food for thought.”
Board member Michael Evans asked if MISO could commission a technology company “that’s already slogging through the big data” to analyze the RTO’s information.
HVDC
MISO has found that DC transmission, which is ideal for transporting large amounts of power over long distances, only becomes as cost effective as AC for lines longer than 600 miles.
Moeller said DC technology could connect MISO resources to ERCOT and the Western Interconnection.
“If there are technologies available to us to move power from Denver to Des Moines, direct current is the way to go,” he said.
Clean Line Energy is MISO’s largest DC merchant, with three interconnection projects in the queue: the Grain Belt Express (which could carry 4,000 MW of wind power from western Kansas to Missouri, Illinois and Indiana), the Rock Island line (3,500 MW of capacity from northwest Iowa to Illinois) and the Plains & Eastern line (4,000 MW of capacity from the Oklahoma Panhandle to Tennessee and Arkansas). The Plains & Eastern project faces opposition from Arkansas’ congressional delegation. (See House Panel OKs Bill Targeting Clean Line Project.) MISO has just three DC lines to date: one in Manitoba and two transferring power from North Dakota into Minnesota.
“They’re substantially faster and more flexible,” Moeller said.
Storage
MISO’s treatment of battery storage as generation will have to change, Moeller said. It cannot be “force fitted” into a generation market definition, he said.
Although energy storage is evolving rapidly, and utilities are beginning to experiment with it, it is not yet competitive in MISO, Moeller said. He said there is no an independent source that has identified when storage will become economically viable.
Moeller also said MISO believes storage’s competitiveness has been hurt by the low cost of gas. While storage technology becomes cheaper and MISO shifts from its dependence on coal, Moeller said the RTO has discussed strategies to more precisely model price volatility, including securing grants for Ph.D.s in university mathematics departments for a more complex algorithm for gas prices and renewables. MISO currently uses U.S. Department of Energy data and simple inflation to forecast gas prices.
MISO Vice President of System Planning and Seams Coordination Jennifer Curran said the RTO expects installed gas capacity to increase in the near future, with 2,700 MW of gas-fired generation projects in advanced stages of study in the generator interconnection queue.
By 2030, MISO expects gas penetration to reach 35%, almost equal to coal’s current 36% share.
MISO said the substantial shifts in generation mix is justification for the RTO to begin making its own independent load forecasts.
Two generation owners on Friday petitioned FERC to block New England states’ efforts to have electric ratepayers underwrite the cost of expanded natural gas pipelines (EL16-93).
NextEra Energy and Public Service Enterprise Group said the proposals by state regulators to release natural gas capacity to electric distribution companies “will render ISO-NE markets unjust, unreasonable and unduly discriminatory, and result in manipulation of the ISO-NE market.”
The generators asked FERC to rule by Aug. 23 and order ISO-NE to draft a “prophylactic tariff fix” within 90 days. They also seek a technical conference and “final” FERC order by the end of January 2017, before the next Forward Capacity Auction in February.
“State regulators in Massachusetts, New Hampshire, Connecticut and Rhode Island are on the verge of implementing a scheme expressly intended to artificially suppress prices in wholesale energy markets in New England,” the companies wrote.
“Having no use for the pipeline capacity, the EDCs would release the capacity at below-market rates — first to gas-fired generators … and then whatever is left will be released to the marketplace,” the complaint continued. “This transportation subsidy would artificially flood ISO-NE markets with gas, thereby unreasonably suppressing gas prices and wholesale power prices.”
The proposal by the EDCs, endorsed in varying stages in proceedings by state regulators, would allow the distributors to recover from their ratepayers the cost of access to expanded pipelines.
EDCs Eversource Energy and National Grid favored the capacity release proposal at a FERC technical conference held last month. (See Utilities Seek OK for Gas Releases to Generators at Technical Conference.) The two are partners in the proposed Access Northeast pipeline at the center of the dispute. It would bring shale gas from the Marcellus region of Pennsylvania into New York and New England.
The Massachusetts Department of Public Utilities, which is the furthest along among the regulators, has ruled such a contract is legal under state law. It is considering a proposal for a 20-year gas supply contract that could be approved as early as October. (See More Pipelines for New England: ‘Gold-plating’ or Necessity?)
Massachusetts Attorney General Maura Healey has supported a lawsuit filed by ENGIE and the Conservation Law Foundation that challenged the legality of such contracts. A ruling by the state’s Supreme Judicial Court is expected soon.
Another proposed pipeline that could have benefited from ratepayer subsidies, Kinder Morgan’s Northeast Energy Direct, was scuttled earlier this year, in part because of the lack of commitments for firm capacity customers. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)
PJM is opening its second competitive project proposal window of the year this week.
Its scope consists of a year 2021 analysis of N-1 and N-1-1 thermal and voltage contingencies; generation deliverability and common mode outages; and load deliverability thermal and voltage.
The window will be open 30 calendar days, PJM said. Those offering proposals during that time will be permitted 15 additional days to submit detailed greenfield reports.
This is the second window for which a new proposal fee will apply for upgrades and greenfield projects. There is no fee for proposed projects costing less than $20 million. A $5,000 fee will be assessed for projects of up to $100 million. Proposals with a projected cost of more than $100 million must be accompanied by a $30,000 fee.
Details on registering were presented at the January Planning Committee meeting.
SPP said last week it is seeking industry experts to serve on a second independent panel to review Order 1000 transmission proposals in 2017.
The panel will review and score proposals for competitive projects approved for construction by SPP’s Board of Directors. The RTO’s first independent expert panel earlier this year awarded a 22.6-mile transmission project to Mid-Kansas Electric. (See SPP Awards First Order 1000 Project — But it May Not be Needed.)
“We are proud of our initial [industry expert panel] process, having now seen it all the way through for the first time,” said Paul Suskie, SPP’s executive vice president of regulatory policy and general counsel. He said the process will be refined based on lessons learned and stakeholder feedback.
SPP said interested candidates must have expertise in at least one of five areas “as it relates to electric transmission”: engineering design, project management and construction, operations, rate design and analysis, and finance.
Applications will be accepted through Sept. 1. Panelists will be selected based on a recommendation by the RTO’s Oversight Committee and approved by the board later this year. Those serving on the panel will be considered contractors and will be compensated through a monthly retainer and hourly rate.
More information on the panel’s application process can be found here.
DETROIT — MISO and its Independent Market Monitor have reconciled their differences and reached a compromise on a redesign of the capacity auction, CEO John Bear told stakeholders at the RTO’s Annual Meeting last week.
Bear made his remarks at Wednesday’s Advisory Committee meeting, which was originally planned to feature a presentation on the new competitive retail solution (CRS), a proposal to create a separate, three-year forward auction for retail-choice areas in the RTO’s footprint.
The delay gives MISO officials and the Monitor, which have disagreed on core aspects of the CRS, more time to work on their “hybrid” proposal. (See MISO: Auction Design July Filing Doubtful.)
Bear refused to give any details on the compromise, saying he preferred discussion to take place at the next Resource Adequacy Subcommittee meeting June 29-30, when the proposal will be officially unveiled. He also said further discussion would take place at a meeting in mid-July.
“If we need more time, we’ll take it. We’re not going to release something that’s half-baked,” Bear said.
MISO stakeholders, however, predicted a tough road to implementation regardless of what is released. Resource Adequacy Subcommittee Chair Gary Mathis told the board that “there’s a very big rift between those that think we shouldn’t be doing this, if ever,” and those in favor of varied approaches to redesigning the auction.
“It makes it hard to work through those issues,” Mathis said. He said he anticipates a “big stress level from stakeholders” as they sift through the revised proposal.
Board member Baljit Dail asked if it would be stalled to the point where it would still be under development in a year.
“No, I think we’ll have a big discussion, and then FERC will have to sort it out just like MISO has had to sort it out,” replied Mathis, who predicted challenges to whatever the RTO files.
Despite the predicted challenges in FERC, MISO board members put pressure on stakeholders to come up with a solution as quickly as possible. Board member Judy Walsh said she hoped MISO would come up with a filing in “some sort of short timeline.”
“The search for absolute consensus is going to lead us to endless delay,” board member Paul Bonavia agreed.
However, Kevin Murray, of the End-Use Customers sector, said any attempt from MISO to implement a hybrid solution in time for the 2017/18 planning year would be too hurried and “circumvent stakeholder process.”
Board Troubled by Forecast Generation Shortfall
At the Board of Directors meeting Thursday, board members said they were troubled by the possible generation shortfall in 2018, as predicted in this year’s MISO-Organization of MISO States Survey. (See OMS-MISO Survey: Generation Shortfall Possible.)
MISO Executive Vice President of Transmission and Technology Clair Moeller told the board that a redesigned capacity auction that sends better price signals could curb the rate of retirements.
“That’s why we continue to push the competitive retail solution and be aggressive, to solve this decline [in generation] before it becomes a reliability problem,” Moeller said.
OMS President Sally Talberg urged implementation of the CRS in time for the 2017/18 planning year.
In the survey, MISO identified 2.5 GW worth of planned retirements and 1.8 GW worth of potential closures in 2017.
Board member Michael Evans asked Moeller if he could provide reassurance that adequate reliability exists in the near future.
“We don’t anticipate significant problems in the local area as long as there is sufficient transfer capability. I am cautiously optimistic that things will be OK,” Moeller said. “In the construction world, we’d say that we used up all our ‘float.’ So we need to get to work, but there’s enough time.”
Evans also asked how many coal and nuclear plants that recently threatened to retire have actually filed for retirement study requests.
MISO legal counsel Stephen Kozey answered that the RTO could provide the total capacity that has filed for retirement but couldn’t name the individual plants.
“It is true that not everything [mentioned] in the press has gone through a [retirement study] request,” Kozey said.
“We may end up with a retirement queue,” Moeller added.
“It might be worthwhile to start doing some intensive ‘what-if’ studies,” Evans said.
Dail asked if the 800-MW increase in forced outages predicted in the survey would be a continuing trend. Moeller said the higher outage rates are the result of using coal plants for short cycles, for which they weren’t designed.
“Not to be an alarmist, but this makes me a bit uneasy,” board member Thomas Rainwater said.
The board then asked if MISO could simply deny generator suspensions and retirements.
“We have the ability to call resources back to maintain local reliability but not to protect resource adequacy,” Moeller answered. He said a market mechanism needs to be created to keep generators online for the sake of resource adequacy.
“So if you need them a day later, you can keep them. If you need them three years from now, you can’t keep them?” Walsh asked.
Snowpack in the Sierra Nevada mountains, depleted after four years of drought, will likely remain in deficit until 2019, according to a University of California, Los Angeles study. The research debunks the notion that the recent El Niño, which increased snowpack levels to about 85% of normal, was a “drought buster.”
Sierra snowmelt accounts for more than 70% of the region’s streamflow, 60% of the state’s water supply and much of the energy output for the state’s extensive system of hydroelectric dams, which declined by two-thirds between 2011 and 2015.
Only one previous drought in 65 years required more than a year of recovery to the snowpack. “The fact that this deficit is so much larger is where this number comes from and why we would expect it to be a multiyear recovery,” said Steve Margulis, the study’s lead.
The Department of Natural Resources will allow the builders of the Dakota Access pipeline to use horizontal drilling methods to construct the Bakken crude pipeline under historic tribal burial grounds in the Big Sioux River Wildlife Area, removing a regulatory impediment to the $3.8 billion pipeline.
The pipeline’s developers, Energy Transfer Partners, suggested the pipeline could be bored 85 feet beneath the surface as a way to resolve the dispute over the recently discovered burial ground. The drilling method would avoid surface disturbances of an open trench. “It’s obviously going to have to go deep enough so it’s not going to disturb the tribal grounds,” DNR spokesman Alan Foster said.
Native Americans said they still opposed the 1,168-mile pipeline. “It is disheartening that they have a green light to move ahead, but I feel very confident that there are a number of landowners, tribes and well-informed citizens who will be standing up to make sure that this pipeline does not get built,” said Dallas Goldtooth, an organizer for the Indigenous Environmental Network.
Westar Energy customers could see an $18 million rate reduction as a result of FERC’s approval of a settlement between Westar Energy and the Corporation Commission over transmission-delivery charges.
FERC on March 30 approved a settlement between Westar and the KCC after determining the company had collected too much money from customers. The ruling came a day before the state commission approved a $25 million increase to Westar transmission delivery charges, adding about $4 to an average customer’s bills.
As a result of those two decisions, Westar updated its transmission costs June 21, dropping the amount charged to customers by $18 million.
Upper Peninsula utilities say their customers will unfairly bear the burden of $49.7 million in MISO reliability charges to keep three coal-fired power plants operating.
The RTO filed a new cost calculation for the plants’ system support resource agreements with FERC, and the bills’ first installments are due July 8. Utilities are blaming the state’s customer choice program, which allowed all large mining customers to switch energy suppliers but capped the rest of the state at 10%.
Cloverland Electric Cooperative owes the most, at nearly $11.3 million. Cloverland CEO Dan Dasho estimated that each customer would have to pay an additional $17 to $20 a month for the next 14 months to satisfy the bill.
Ann Arbor Eyes More Solar to Combat Climate Change
Ann Arbor has unveiled a plan to cut the city’s carbon emissions 25% by 2025, aiming to add the equivalent of 2.4 MW in solar installations every year over the next decade.
The City Council unanimously approved a resolution that supports solar-friendly measures, including instructing city departments to abide by the Clean Energy Coalition’s Solar Ready Community guidelines.
Consumers Energy Contests Taxable Value of Wind Farm
Consumers Energy is challenging the tax assessment of its 111-MW Cross Winds Energy Park in Tuscola County, where several other wind farms are also seeking reductions in their property tax payments.
The utility filed petitions with the Tax Tribunal, arguing that the assessed value of the $250 million wind farm was too high and asking for refunds for overpayment.
NextEra Energy Resources has filed a similar petition regarding their Tuscola I and Tuscola II windfarms. Tuscola County Controller Mike Hoagland said the assessed values of “most, if not all” the county’s wind turbines are being challenged.
Gov. Mark Dayton said his state will ask the full panel of the 8th U.S. Circuit Court of Appeals to hear its appeal of a lower court ruling that the state’s clean energy law illegally regulates out-of-state energy companies.
A three-judge panel of the 8th Circuit upheld a ruling that the state’s law, which restricted electricity imports from power plants that increase the state’s greenhouse gases, was unconstitutional.
Entergy Forced to Shut Down Indian Point Because of Leak
A week after it came back into service following a three-month outage, Entergy once again shut down Unit 2 at its Indian Point nuclear plant so workers could repair a leaking water intake pipe.
The leak in the cooling-water intake was unrelated to the problem that Entergy encountered with damaged baffle bolts, which required the recent protracted outage to repair. But Gov. Andrew Cuomo slammed the plant’s operators for the latest in a series of problems at the twin-reactor complex.
“This is yet another sign that the aging and wearing away of important components at the facility are having a direct and unacceptable impact on safety and is further proof that the plant is not a reliable generation resource,” Cuomo said.
The Senate passed a bill that will prohibit wind turbines from being erected in the central and eastern portions of the state, threating two proposed wind farms with a combined output of 400 MW.
Sen. Harry Brown (R-Onslow County), the bill’s sponsor, said the wind turbines present a danger to low-flying aircraft, especially military jets and helicopters operating out of the several large bases, including Fort Bragg and Cherry Point Marine Air Station. “Anything we can do to protect them is important,” he said.
A Department of Defense spokesman, however, said Brown’s legislative effort was done without any consultation from the military. “We have not officially been engaged or involved with North Carolina regarding the latest proposed revisions to state law,” Lt. Col. James B. Brindle said.
Duke Energy Progress has proposed to cut rates for its 1.35 million customers to reflect lower energy costs.
The proposal, made last week to the Utilities Commission, includes some rate increases and some decreases on various components of its service.
Overall, residential customers would see a 4.9% drop; industrial consumers, 5.7%; and commercial customers, 6.3%. The rates would go into effect on Dec. 1.
The Public Service Commission last week approved a proposed $153 million wind farm and associated electric transmission line in Oliver and Morton counties. The three-member panel unanimously approved the project’s siting application, clearing the way for construction to start.
A NextEra Energy subsidiary is developing the wind farm, which will include up to 48 turbines and produce up to 100 MW of power. The project also includes a 4.5-mile, $11.4 million transmission line to connect the wind farm to the grid.
The Public Service Commission may vote as early as next month on the 72-turbine Brady Wind Energy Center II project. The PSC has meetings scheduled for July 6 and July 20.
Commissioner Brian Kalk said the commission did not have many additional questions for representatives of Brady Wind, a subsidiary of NextEra Energy.
The PSC has already approved Brady Wind I, the first phase of the project, which consists of 87 turbines and a 19-mile transmission line.
Gov. John Kasich has nominated energy industry attorney Howard Petricoff to fill a vacant seat on the Public Utilities Commission, which spurred Senate President Keith Faber, a Republican, to call for hearings into the Democratic nominee’s record.
Petricoff recently retired as head of the energy section of a large Columbus law firm and had many competitive retail energy suppliers as clients. Faber said Petricoff’s legal work “raised questions about his ability to make neutral decisions given his past activism.”
If Petricoff is confirmed by the Senate, PUCO would have two Republicans, two independents and one Democrat. State law mandates that no party can have more than three of the five seats on the commission, but it does not require at least one member of each party.
An overflow audience of nearly 300 residents turned out to debate a zoning proposal by a subsidiary of Iberdrola Renewables to build 37 wind turbines on 266 acres in Penn Forest Township, Carbon County.
The crowd, mostly hostile to the proposal, jeered representatives of Iberdrola and the Sierra Club, which supports the wind project. The 525-foot-high turbines and blades would be built on land leased from the Bethlehem Authority, the financial arm of the town’s water business. It would be located less than a mile of several homes.
Bills aimed to block a natural gas power plant and to shift a wind project’s interconnection costs to ratepayers failed in the legislative session, but other proposals favored by clean energy advocates moved forward, including an extension of the state’s renewable portfolio standard from 14.5% by 2019 to 38.5% by 2035.
The legislature also extended the Renewable Energy Fund to 2022, which provides grants and loans to install renewable-energy systems.
The sponsors of a federally funded experiment to explore deep underground storage of nuclear waste will have to search for a new site.
Spink County turned away technology development company Battelle from conducting experiments that involve drilling as much as 3 miles deep into bedrock to test storing waste in boreholes. The experiment wouldn’t involve any radioactive waste, but wary residents expressed fear the tests would increase the chances their area would eventually be chosen for a waste well.
“It was a good spot to try and do our science experiment, so we’re disappointed we couldn’t work something out with them,” a Battelle spokesman said. “But we understand.”
Lubbock Power & Light’s Electric Utility Board has proposed a 2% increase in customer bills and $70.9 million in infrastructure improvements. The budget will be presented this summer to the Lubbock City Council for final approval.
The rate increase would pay for the projected $333 million worth of capital improvements LP&L plans in the next six years, largely in preparation for the switch to ERCOT in 2019, when the city’s wholesale contract with Xcel Energy expires.
The inner transmission loop will be upgraded to 69 kV and the outer loop to 115 kV as part of the infrastructure improvements.
Less than a week after obtaining its air permit from the Air Pollution Control Board, Dominion Virginia Power began construction on its 1,588-MW Greensville County Power Station. The company said it expects the $1.3 billion plant to go into service by 2019.
Dominion says the power station will be a major boost for the region’s economy, with up to $8 million in property taxes paid to Greensville County in its first year of operation. The company also said its customers will save about $2 billion over the plant’s expected 36-year life, as the company will not need to purchase power on the market.
“The air board has approved and the Virginia Department of Environmental Quality has issued a very strict permit, which will require that our station be one of the most efficient and environmentally protective natural-gas fueled power stations in the world,” Dominion’s Pamela F. Faggert said.
NextEra Energy and Public Service Enterprise Group said the proposals by state regulators to release natural gas capacity to electric distribution companies “will render ISO-NE markets unjust, unreasonable and unduly discriminatory, and result in manipulation of the ISO-NE market.”
Snowpack in the Sierra Nevada mountains, depleted after four years of drought, will likely remain in deficit until 2019, according to a University of California, Los Angeles 
The Department of Natural Resources will allow the builders of the Dakota Access pipeline to use horizontal drilling methods to construct the Bakken crude pipeline under historic tribal burial grounds in the Big Sioux River Wildlife Area, removing a regulatory impediment to the $3.8 billion pipeline.
Westar Energy customers could see an $18 million rate reduction as a result of FERC’s approval of a settlement between Westar Energy and the Corporation Commission over transmission-delivery charges.
Consumers Energy is challenging the tax assessment of its 111-MW Cross Winds Energy Park in Tuscola County, where several other wind farms are also seeking reductions in their property tax payments.
A week after it came back into service following a three-month outage, Entergy once again shut down Unit 2 at its Indian Point nuclear plant so workers could repair a leaking water intake pipe.
Duke Energy Progress has proposed to cut rates for its 1.35 million customers to reflect lower energy costs.
The Public Service Commission last week approved a proposed $153 million wind farm and associated electric transmission line in Oliver and Morton counties. The three-member panel unanimously approved the project’s siting application, clearing the way for construction to start.
Lubbock Power & Light’s Electric Utility Board has proposed a 2% increase in customer bills and $70.9 million in infrastructure improvements. The budget will be presented this summer to the Lubbock City Council for final approval.
Less than a week after obtaining its air permit from the Air Pollution Control Board, Dominion Virginia Power began construction on its 1,588-MW Greensville County Power Station. The company said it expects the $1.3 billion plant to go into service by 2019.