Disputes between utilities and solar providers aren’t limited to North Carolina. (See story, Solar Industry at Crossroads in N.C.) Among the battlegrounds are Iowa, Wisconsin, Arizona and Missouri.
On Friday, the Iowa Supreme Court came down on the side of solar, ruling that a solar company was not violating state law by selling electricity generated by a rooftop installation to the city of Dubuque. Utilities Alliant Energy and MidAmerican Energy unsuccessfully argued that third-party purchase power agreements such as the one involving Dubuque violate state laws giving them exclusive energy sales rights.
In Wisconsin, We Energies has filed a proposal with state regulators to bar its customers from leasing solar arrays. The company also seeks a surcharge on customers who are generating their own power.
Arizona Public Service Company wants the change the state net metering rules, offsetting a solar credit with a monthly charge, and state lawmakers there are considering a tax on rooftop installation.
In Missouri, Ameren and Kansas City Power & Light are asking the state Public Service Commission to end all solar rebates.
The Wisconsin, Arizona and Missouri cases await resolution.
The Bureau of Ocean Energy Management will take bids Aug. 19 for the rights to lease nearly 80,000 acres of the Atlantic Ocean off the coast of Maryland for wind energy projects. It will be the sixth commercial offshore wind energy lease awarded by the federal government, after three off of New England and one each off Virginia and Delaware. Sixteen companies have been qualified to bid on the Maryland Wind Energy Area, which could support between 850 MW and 1,450 MW of commercial wind generation. The area is about 10 miles off the coast of Ocean City, Md.
Arizona Public Service Co. will spend $3.25 million in a settlement with the Federal Energy Regulatory Commission over its role in a Sept. 8, 2011 blackout that left more than 5 million people in California, Arizona and Mexico without power for up to 12 hours.
A joint FERC/North American Electric Reliability Corporation (NERC) examination of the incident found that APS violated NERC reliability standards. Since the event, APS has worked with regulatory and industry organizations to make improvements, FERC said.
The company will pay $1 million each to the U.S. Treasury and NERC, and spend $1.25 million on reliability investments. “APS’ reliability enhancements will improve the reliability of the Western Interconnection and are valued at substantially more than the $1.25 million credit granted,” Acting FERC Chairman Cheryl LaFleur said.
The Supreme Court said it will not consider Kansas City Power & Light Co.’s appeal of a lower court ruling that denied the company federally approved transmission costs.
The company incurred the costs in moving power 500 miles from a natural gas-fired plant in the Mississippi Delta to customers in western Missouri. At issue are transmission costs associated with the Crossroads plant, which was originally built as a merchant generator but was folded into the rate base after KCP&L’s parent company was unable to sell it.
The plant only operates in the summer, but the Missouri Public Service Commission earlier ruled that it had to pay transmission access fees on a year-round basis. The commission approved the purchase of power from the plant but wouldn’t approve the estimated $5 million annual transmission costs, saying they were not just and reasonable.
The House passed a bipartisan amendment to block a new capacity zone in the New York ISO last week as part of the 2015 Energy and Water Appropriations Bill.
News of the new zone, which would increase residential energy costs, sparked protests after the Federal Energy Regulatory Commission approved it in January. Republican Rep. Chris Gibson said he and Democratic Rep. Sean Maloney introduced the amendment to protect residential consumers. “We will not relent in our efforts to prevent this agency from doing further damage to families and the economy of the Hudson Valley, where people are already struggling to make ends meet,” Gibson said in a news release. A Senate vote is expected in the fall.
Proponents of the new capacity zone, which went into effect May 1, hope it will spur the construction of new generation below a transmission bottleneck.
Elizabeth Sherwood-Randall participates in a video conference with President Obama and French President Nicolas Sarkozy in 2012. (Source: White House)
President Obama has nominated Elizabeth Sherwood-Randall, a nuclear proliferation and defense policy official, for Deputy Secretary of Energy. Sherwood-Randall is currently the White House coordinator for defense policy and has also acted as a foreign policy expert. In addition to working on nuclear weapons policy and strategy, she also will be wading into the issues surrounding hydraulic fracturing.
DOE to Start Cleanup of Hanford’s “Atomic Man” Site
Clay Rowan, a health physics technician, in the McCluskey Room to take radiation readings in June 2005. (Source: Department of Energy)
The site of a 1976 plutonium explosion at the Hanford Nuclear Reservation in Washington state is slated for cleanup this summer. Worker Harold McCluskey was exposed to the highest dose of radiation from the chemical element americium on record — 500 times the safe standard — in the accident. Americium is a byproduct of plutonium.
McCluskey, then 64, became known as the “Atomic Man” after the incident. He was put into an isolation unit, where he stayed for five months. His body’s radiation level fell by 80 percent within a year. He died in 1987 of heart disease, said to be unrelated to the accident. Cleanup of the “McCluskey Room” is expected to be completed by 2016.
Rep. Sam Graves (R-Mo.) last week filed a bill that would halt every Environmental Protection Agency regulation now in the works and mandate the review of all other EPA rules. If passed, the bill would effectively halt EPA action on any of its rules until after the review.
Graves, chairman of the Small Business Committee, is incensed over the EPA’s proposed “Waters of the United States” rule, which would redefine federal jurisdiction over lakes and streams covered by the Clean Water Act. Many of Graves’ constituents are farmers who could be impacted by any change in water laws. Graves’ “Stop the EPA Act,” would also hamstring the EPA’s recent emissions rules covering power plants.
The Senate is scheduled to vote today on the confirmation of Norman Bay to the Federal Energy Regulatory Commission and a new term for Acting Chair Cheryl LaFleur. The Senate Energy and Natural Resources Committee approved Bay’s nomination last month under a deal with the White House that would delay Bay’s ascension to the chairmanship for nine months.
Southern Company’s 25-MW demonstration carbon-capture plant at Alabama Power’s Plant Barry near Mobile, Ala., won the Southeastern Electric Exchange’s 2014 Industry Excellence Chairman’s Award. The project, demonstrating carbon capture and sequestration at a pulverized-coal plant, captures about 150,000 tons of carbon dioxide annually. The carbon dioxide is sent through a 12-mile pipeline to an oil field and injected into a geologic formation 9,500 feet below the surface.
Exelon’s Oyster Creek Nuke Shut Down Twice in a Week
Two unplanned shutdowns at Exelon Nuclear’s Oyster Creek Generating Station in New Jersey last week prompted the Nuclear Regulatory Commission to change the plant’s performance ranking from “green” to “white.” Both the company and the NRC said there were no immediate safety concerns from either event.
The first shutdown occurred last Monday, when the plant went down to fix safety equipment inside the reactor’s dry well. The second occurred Friday, as the reactor was powering up after the first incident, due to a problem in the plant’s condenser. “It is crucial that during start-up, every system operates flawlessly. If anything is not as expected, operators stop the startup process and address the issue,” company spokeswoman Suzanne D’Ambrosio said. The aging plant is due to shut down permanently in 2019.
Public Service Electric & Gas launched a new menu of online tools designed to give customers more information about outages and how long it will take to restore power.
The new tools are a response to the company’s experience during Hurricane Sandy, when millions were left without power and customers complained about being unable to get through to the company or get good information about restoration times. The new tools — at outagecenter.pseg.com — let customers see how many outages there are, and where, down to the neighborhood level. It will also give up-to-date restoration times, the company said. Information on the site will be updated every 15 minutes.
Indiana Michigan Power says it will ask state regulators for permission to construct five solar plants in Indiana and Michigan for its Clean Energy Solar Pilot Project. The company hasn’t released information on locations or sizes of the individual plants, but it said they will cost about $38 million to build. The project could be under construction by 2016, depending on how long it takes to get regulatory approval, the company said.
A ship that drills for ocean floor core samples has set up off the coast of Virginia Beach, giving beachgoers their first glimpse of the possible future of offshore wind towers. The 110-foot “offshore construction jackup” ship steamed from the Gulf of Mexico to the Virginia coast and began drilling about 300 yards offshore of Camp Pendleton, where transmission lines would be laid.
The ship will also drill at the proposed wind farm site about 24 miles offshore. Drilling will be completed by July 20, according to Dominion Virginia Power, the company that plans to build the offshore wind farm.
PJM has created a closed loop interface to capture the pricing of demand response in a transmission sub-zone spanning the Pennsylvania-Ohio border near New Castle, Pa. The interface, which took effect July 1, will be used in real-time when load management is deployed in the area, part of the ATSI zone.
PJM officials said DR may be necessary during outages anticipated with the construction of system upgrades. The upgrades, a result of plant retirements in the area, are expected to be completed in spring 2015.
The interface won’t be used in Financial Transmission Rights auctions or other modeling.
Difficult to Forecast
PJM’s Rebecca Carroll told the Operating Committee that operators will attempt to model the interface in the day-ahead market when possible. “But being able to forecast that is going to be very difficult,” she said, noting that operators generally don’t know whether they will be dispatching DR until a few hours before it is needed.
PJM’s Joe Ciabbatoni said PJM now has a formally documented process for establishing pricing interfaces. “`There should be more of these [interfaces] bubbling up” in the future, he said.
Mike Bryson, executive director of system operations, said that based on the lessons of the unexpected September 2013 heat wave, PJM will be more “proactive” in identifying areas where it may declare subzones for pricing DR. PJM created a closed loop interface in ATSI to capture DR prices that hit the maximum of $1,800/MWh on Sept. 10, when the RTO found itself unprepared for a late summer heat wave that pushed demand over 144,000 MW. (See PJM Surprised by September Heat Wave.)
Bryson said officials also will consider recalling and rescheduling planned outages related to the New Castle upgrades when it anticipates high load days.
In May, the Federal Energy Regulatory Commission rejected PJM’s call for sub-zonal dispatch inside an operating day, saying the RTO had failed to prove the change would not result in “prohibitive costs” to DR providers. Bryson said the order allows sub-zonal dispatch ordered the day before and voluntary compliance with in-day dispatches.
On July 8, the commission said it will take another look at the issue after DR providers Comverge and EnergyConnect contended even next-day sub-zonal dispatch would be a hardship.
Notification Process Sought
At the Market Implementation Committee Wednesday, Bruce Bleiweis of DC Energy and Barry Trayers of Citigroup Energy asked PJM to provide more lead time and transparency when it considers new pricing interfaces.
Bleiweis said PJM should post a public notice when it identifies an issue that may result in an interface. “We feel that’s a superior process to not knowing there was an issue internally discussed,” he said.
Trayers suggested a formal notification process similar to that for creation of special protection schemes.
RALEIGH, N.C. — Far from the sunny Southwest, North Carolina has unexpectedly become one of the fastest-growing destinations for solar energy developers in the nation. But a battle pitting the state’s largest utilities against environmentalists could stop that growth in its tracks.
At stake is the way solar energy is sold in the state. The state Utilities Commission currently requires Duke Energy, Duke Energy Progress and Dominion Power North Carolina to enter into 15-year contracts with solar producers of any project 5 MW or smaller. Duke and Dominion have asked the commission to cut the length of the contracts to five years and reduce the size of qualifying facilities to 100 kW — 2% of the current size.
Solar power companies and environmentalists countered by asking that plants producing up to 10 MW be included and that the contract term be lengthened to 20 years.
How North Carolina Got Bright
The contracts for such qualifying facilities (QFs) are priced at avoided costs, currently set at about 6.5 cents per kWh.
The commission meets every two years to set the rates. At the most recent proceeding in February, the commission asked all parties to reexamine the contract rules to determine if they should be adjusted.
The current rules were set when the solar industry was just getting on its feet. It was designed to provide a ready market for the nascent industry by encouraging utilities to add renewable energy to their portfolios.
At 750 MW, North Carolina ranks fourth among states with installed solar capacity, behind only California, Arizona and New Jersey, according to the Solar Energy Industries Association (SEIA). The state added 335 MW last year, ranking third in the U.S.
In 2007, North Carolina enacted a renewable portfolio standard that called for utilities to obtain 12.5% of their electricity from renewables by 2021. The state has also subsidized renewables through a tax credit.
Growing Clout
Solar also grew as a result of North Carolina’s efforts to lure energy-gobbling data centers to the state. Apple’s data center in Maiden came with its own 20-MW solar farm. Google and other companies pressed Duke to win approval of a Green Source Rider allowing companies to pay the utility a slightly higher rate in return for renewable energy.
The state’s QF program became an unexpectedly large contributor to the industry’s growth, according to Ivan Urlaub, executive director of the North Carolina Sustainable Energy Association (NCSEA), an umbrella group of sustainable energy providers. “Those small regulatory rules, combined with a renewable energy tax credit, were sufficient to take what was otherwise a small market and carve out a space for entrepreneurs to jump in and compete on price and quality,” Urlaub told Slate.
The state now has 570 green energy firms employing 18,400 people, according to Urlaub. The SEIA says $787 million was invested in solar plants in the state last year.
That growth has given the industry the clout to be a credible opponent to utilities. A bill that would have repealed the state’s renewable portfolio standard died in committee last year.
Duke Hearts Solar?
NC WARN’s ad attacking Duke’s position on solar power. Note: not actually clickable on our site.
In the run up to four days of hearings on the contract issue last week, combatants filed expert testimony and the environmental group NC WARN launched a state-wide ad campaign.
“Why does Duke Energy Hate Solar?” its website and full-page ads asked. “Duke actually likes solar — just not for North Carolina solar companies.”
In an interview, NC WARN Executive Director Jim Warren explained his organization’s support for the solar groups’ position. “We think it’s good for the community, the solar industry — and even for the utilities, since they’re facing a corporate death spiral if they don’t adapt to the fast shift toward distributed energy,” he said.
“More solar installations added to the grid would further reduce the need for Duke to build new power plants and raise rates. So, while more solar on the grid has tremendous benefits to all customers, it is an existential threat to Duke Energy’s business model and profits.”
Duke spokesman Randy Wheeless insisted the company doesn’t hate solar. In fact, he said, Duke has been a major proponent of solar energy all along, and continues to be. The company owns 140 MW of solar at 20 sites in eight states, about 3% of its 49,626 MW of generation capacity.
“Duke and Duke Progress were in the top 10 [nationally] in bringing on new solar” projects in 2013, he said. “Duke Energy has wind and solar [facilities] in 12 states. When you add all those facts together, it’s hard to say Duke is anti-solar or trying to kill solar. I think Duke has a pretty good story to tell.”
Wheeless noted that most of the solar projects in North Carolina were 5 MW or lower “because the standard offer is the most attractive one” for producers. He said the utilities’ sought to decrease the QF size to allow them the “flexibility to negotiate the contracts.”
Pass Through to Consumers
Shortening the length of purchase power agreements with solar producers will benefit consumers, Wheeless said. “We basically say, ‘Look, the PPA is a pass through to consumers.’ When you throw a contract out 15 years to 20 years, and you look at that curve, we think most of the risk is being borne by the customers. The odds are better that over the course of the longer contract, the customers will pay more, not less. We feel [customers] would benefit if they were 10 years. Customers would be less likely to overpay.”
Betsy McCorkle, government affairs director for the NCSEA, declined to be interviewed on the issue Friday.
But the NCSEA lined up experts to file written testimony. R.T. Beach, an energy consultant from California, filed a lengthy response with the commission outlining why solar projects benefit both utilities and customers.
Lumpy Additions
“Most of the QFs in North Carolina are 5 MW or smaller. In contrast, typical utility additions of capacity are in increments of at least 100 MW, and often more, as shown by the utilities’ current resource plans,” Beach wrote. “These large central station units require significantly longer time to develop, permit and build.
“As a result of the long lead times and the large, ‘lumpy’ nature of utility capacity additions, new utility plants must be sized to provide much more than the amount of capacity [that] the utility needs in the year in which the new plant enters service. The result is that ratepayers may have to pay for years of excess capacity until demand ‘catches up’ to the last major addition,” Beach wrote.
Off Switch
NCSEA witnesses and other solar proponents say that decreasing the QF size and PPA length would pose an existential threat to the solar generation industry. Beach said the change would press an “‘off switch’ that would be likely to significantly slow, if not halt, QF development.”
Banks would be less likely to finance larger projects if they were not QF-rated, and shorter PPAs would also result in more difficulty obtaining financing. It has already happened in other markets, solar proponents say.
Beach cited Idaho regulators’ decision to allow Idaho Power to reduce its standard contract size to 100 kW from 10 MW. “The practical result of this order has been to halt further wind development in Idaho, even though wind QFs are entitled to negotiate with the Idaho utilities,” he said. (See related story, Utilities, Solar Industry Square Off in Other States.)
Consumer Response
The battle has captured the attention of North Carolina residents. The docket includes dozens of emails and letters from consumers.
“Duke Energy’s claims of sensitivity to environmental concerns must be viewed with skepticism, given their recent and historical performance in environmental protection,” wrote Sharon Fortner of Winston-Salem. “This regulated monopoly will have to be forced to treat solar generation fairly; it will not do it on its own.”
A decision is expected before the end of the year.
Public Service Enterprise Group, American Electric Power and FirstEnergy are among the utilities with the greatest risk of seeing their transmission rates decline as a result of the Federal Energy Regulatory Commission’s new formula for determining returns on equity, according to a new study.
Despite the new FERC methodology, however, transmission utilities still remain attractive investments with a “wide economic moat” similar to those for oil and gas pipelines, according to the study by Morningstar Institutional Equity Research.
Zone of Reasonableness
Last month, FERC changed the way it sets return on equity (ROE) rates for electric utilities, moving to a process it has long used for natural gas and oil pipelines. Ruling in a case involving New England transmission owners, it tentatively set the “zone of reasonableness” at 7.03% to 11.74%. The commission set the TOs’ base rate at 10.57%, a reduction from the previous 11.14%. (See FERC Splits over ROE.)
Utilities with FERC-approved returns on equity in the upper half of the zone could face reduced returns if Section 206 complaints are filed against them, Morningstar said. Such complaints are currently pending against Florida Power Corp., Duke Energy Florida and Southwestern Public Service Co.
Others vulnerable to rate cuts include ITC (currently earning rates of 12.38% to 13.88%) and PSEG (11.68% to 12.93%), according to the report.
Rate cuts could also be in the future for AEP and FirstEnergy, which have base ROEs above 10.57%, but the impact will be limited because their FERC-regulated transmission represents a small portion of their rate base.
By contrast, Edison International, Pacific Gas & Electric and Xcel Energy have FERC-allowed returns on equity near or below the base ROE for New England and might win increases, Morningstar said.
Wide Moat
Even after the reductions, FERC’s ROEs will exceed the average state-allowed ROEs, the report says.
The report cites several reasons why electric transmission is the “only regulated utility business with a wide economic moat”: Its impact on reliability and access to cheap generation; environmental rules encouraging remote renewable energy resources; and the certainty of cost recovery under FERC rules, which lowers utilities’ cost of capital.
“Transmission remains heavily regulated and faces some imminent competitive threats, but its efficient-scale competitive advantage is so strong that we expect returns on utilities’ transmission investments will continue to exceed costs of capital for many years,” the report says.
Data Center, Power Plant Plan Dies After UD Says No
A controversial plan to build a data center and a 279-MW power plant at the University of Delaware came to a halt last week, as the university terminated the lease agreement with the proposed developer, The Data Center LLC. A university working group decided the project didn’t fit in with the university’s plans for the site, a former Chrysler assembly plant that is now home to the university’s Science & Technology Advanced Research Campus.
The working group of faculty and administrators said the scale of the power plant raised doubt about Data Center’s claims of energy efficiency. The plan was “not consistent with a high-quality development and first-class science and technology campus,” the group said in a report. Gene Kern, president of the development company, said he disagrees with UD that the lease can be terminated for the reasons stated and is examining its legal options.
The Public Service Commission will hold three public hearings in September to gather comments regarding Exelon’s acquisition of Pepco Holdings Inc. The proposed $6.8 billion merger was announced in April.
The commission has said it will issue a final order on the merger by January. It will have a full slate of commissioners to do so, now that the state Senate has confirmed Wilmington’s former economic development director, Harold Gray, for a seat on the panel. Gray assumes the seat vacated by former commission member Arnetta McRae, who left the PSC in 2011 to take a job in the District of Columbia.
The merger needs the approval of state regulators in Delaware, Maryland, New Jersey and Virginia, as well as regulators in D.C. Federal regulatory approval is also needed. Pepco shareholders are expected to vote on the merger in August.
Illinois Attorney General Lisa Madigan slammed Commonwealth Edison for seeking ratepayer contributions to pay for $88 million in bonuses to employees. Madigan said she discovered the company’s request to have customers pay for the bonuses while examining ComEd’s rate request, now before the state Commerce Commission. In a complaint filed last week, Madigan said the company included in its request to recover $275 million in costs. She told the ICC that state law does not allow “incentive compensation expense that is based on net income or an affiliate’s earnings per share” to be funded by customer-borne rates.
The state is in the process of finding a new member of the Indiana Utility Regulatory Commission. The slot opened when Commission Chairman Jim Atterholt accepted a position as Gov. Mike Pence’s chief of staff. The application deadline closed July 11, and the nomination committee is scheduled to have a public meeting July 30 to interview candidates. The committee will then send three names to Pence, who will select the replacement.
Detroit installed its 10,000th light emitting diode (LED) streetlight on July 1 and plans to have 65,000 in place by the end of 2016. The new lights are more energy efficient and attractive, the city says, and will help reduce crime.
The Michigan Public Service Commission recently initiated a subsidy for LED streetlights. “This order itself wasn’t anything earth-shattering,” MPSC energy efficiency manager Rob Ozar said. “What is earth-shattering is that LED street lighting is taking the state by storm. We expect LED lighting to take 80% of the market share.”
The program allows rebates of $47 per bulb, Ozar said, which covers about half of the cost difference between an LED bulb and a typical bulb.
The Board of Public Utilities is considering a proposal to prohibit third-party suppliers from making false or misleading statements to residential customers, and barring such companies from contacting customers if they don’t already do business with them. The move, which will be discussed in a July 17 hearing, is in response to a spate of complaints from customers dissatisfied after switching suppliers. Among the changes being considered are defining “guaranteed savings” from third-party suppliers, especially in connection with variable-price contracts.
Leaders in a town that could be the site of a number of Jersey Central Power & Light transmission line expansions are unhappy with the way the proposed power line projects are being explained to them. Montville Township Mayor Dan Kostka said he and others noticed that the map JCP&L showed them of the proposed expansion didn’t match those showed to neighboring towns. JCP&L is considering updating a transmission line that could bring 100-foot towers and 230-kV lines to the town.
“Some of the routes that have been planned or proposed have not been presented to this governing body,” Borough Attorney Fred Semrau said. He is drafting a letter of objection to the Board of Public Utilities questioning whether JCP&L has been transparent during the process, he said.
University of Dayton to Divest Fossil Fuel Holdings
The University of Dayton announced last week that it will divest all coal and fossil fuel investments from its $670 million investment pool, making it the first Catholic university to join the ranks of colleges and universities making similar decisions. The university said the move was made with an eye toward slowing climate change. “As a Catholic university, it’s our responsibility to serve as good stewards of the Earth. So we cannot ignore the negative consequences of climate change,” President Daniel J. Curran said. The move will affect about $35 million in investments, he said.
West Bradford Township supervisors announced last week they will officially oppose Sunoco Logistics’ effort to get public utility status for a proposed natural gas line that would pass through the town. Sunoco decided to seek public utility status for the Mariner East project in order to bypass local authorization after other towns balked at the plan.
Sunoco wants to build the line in order to bring gas extracted in western Pennsylvania to a refinery on the Delaware River. Marcus Hook Borough and several trade groups have announced support for the project.
PPL last week asked the Public Utility Commission to pass through to consumers $450 million in costs to install smart meters. PPL plans to replace its 1.4 million meters between 2017 and 2019.
The company said the program would boost customer bills by 58 cents per month in 2015, rising to $4.50 in 2020 and falling to $2.79 after 2021.
Met-Ed is completing a $9.2 million project that rebuilt four miles of a 69-kV line and added five miles to the circuit. The project used more than 80 new poles and included new circuit breakers at substations. Both lines should be in service by the end of July, the company said. Met-Ed, a subsidiary of FirstEnergy, services 560,000 customers in 15 Pennsylvania counties.
FirstEnergy Completes New Line in Armstrong County
FirstEnergy finished a $31 million project that included a new 345-kV substation and 1.6 miles of transmission line that will improve reliability in the Armstrong County area, the company said. A large transformer was built next to FirstEnergy’s deactivated Armstrong Power Plant, and a new control room was built to house controls that had been at the plant.
AEP subsidiaries Appalachian Power and Wheeling Power have filed a request to increase revenue by $226 million, which would boost electricity rates by about 17%. The companies say the rate increase is needed to maintain transmission and distribution lines and to run its generating plants. The request cites costs resulting from two storms in 2012. Customer rates in West Virginia haven’t increased since 2011.
Members last week gave initial approval to a manual change that will make it easier for banks to purchase capacity providers’ revenue streams. The Market Implementation Committee approved a change proposed by Citigroup Energy to allow auction-specific transactions to be entered into PJM’s eRPM system after the auction that initiated them.
Under current rules, such transactions cannot be submitted to PJM until after the third incremental auction for a delivery year. The MIC approved changes to Manual 18 by acclamation, sending the issue on to the Markets and Reliability Committee for final approval. (See Stakeholders Look to Expedite Auction-Specific Transactions.)
Despite closing its Wisconsin nuclear plant prematurely last year, Dominion Resources wants to keep its options open in Virginia, where it is considering a third unit at its North Anna nuclear plant.
But it hasn’t done any analysis to compare the risks of a new plant against an increasing reliance on natural gas-fired generation, Virginia State Corporation Commission staff said in a filing last week.
Responding to Dominion Virginia Power’s 2013 Integrated Resource Plan, staff said such an analysis should be included in the company’s next IRP in 2015 in order to determine which option the company should follow in the future.
Dominion “believes that uncertainty associated with the price of natural gas over the long term is a greater risk than the development cost uncertainty of a nuclear unit. However, the company concedes that no analysis has been performed to support this assertion,” SCC staff said. Staff said Dominion has indicated a willingness to conduct the analysis.
Two Plans
In its 2013 IRP, Dominion presented two different plans, one it called the “Base Plan” that calls for the expansion of generating capacity through new natural gas-fired plants, and one it calls the “Fuel Diversity Plan,” which includes low-emission options and does not rely so heavily on natural gas.
Both plans are very similar in the short run, with the major difference being that the latter plan includes the construction of North Anna 3. The company has chosen to follow the Base Plan, the least cost option, but it will also continue to go “forward with reasonable development efforts of additional resources included in the Fuel Diversity Plan,” which “would preserve the company’s ability to implement these alternatives should future conditions warrant,” SCC staff noted.
While natural gas plant projects have low development cost risk, the historically volatile fluctuating fuel price creates the risk of high operating costs. Nuclear plants generally have low operating costs, but their construction is very complicated and prone to cost overruns.
“In other words, there is a risk trade-off of higher operating cost risks with the Base Plan and higher project development cost risks with the Fuel Diversity Plan,” SCC staff said. “Staff was unable to determine whether the Base Plan contains too much operating cost risk, or whether the development cost risk associated with the Fuel Diversity Plan is greater than or less than the reduction in operating cost risk the Fuel Diversity Plan would achieve, because the company did not perform an analysis of this risk trade-off in its IRP.”
Dominion, which applied for Nuclear Regulatory Commission approval of North Anna 3 in 2003, has not committed to building the unit. In its IRP, the company said it would make its final decision once it received a Combined Operating License from the NRC. The unit would be completed no earlier than 2024.
Risky Business
The recent boom in natural gas production, resulting in cheap prices, has not been kind to the nuclear industry. Dominion learned this the hard way last year, when the company was forced to close the 556-MW Kewaunee Power Station, which it had purchased in 2005 for $192 million. After utilities did not renew their power contracts with the Wisconsin plant and Dominion failed to buy other nuclear plants in the region, the company attempted to sell Kewaunee in 2011. When it became apparent there were no buyers, Dominion closed it.
Kewaunee, which opened in 1974, closed a year shy of its 40th birthday, when its license would have needed renewal. Staff at the plant are now beginning the long process of decommissioning it.
With North Anna 3, Dominion seeks to keep all of its options on the table. Mark Kanz, local affairs manager for Kewaunee, recently told Nuclear Power International magazine that the prospect of North Anna 3 “proves that the company sees the benefit of nuclear and is looking forward to continuing that into the future.”
SCC staff also wants the company to compare the costs of building a third unit with the costs of extending the operating licenses of the first two, along with the licenses of the two units at its Surry nuclear plant.
“Given that these units still provide extremely efficient and dependable baseload generation for the company, and given the extremely high costs of constructing new nuclear plants, staff believes that the company should engage in serious discussions with discussions with the NRC to determine whether renewing these licenses is possible.”
The staff noted that it is unknown whether the NRC would grant renewals to the current units. The units would be 60-years-old when their licenses — already extended by 20 years — expired. The NRC expects the first application for an extension beyond 60 years to be filed in 2018 or 2019. Without additional license extensions, the country would face a wave of nuclear plant retirements during the next decade.
Two losing bidders for the Artificial Island transmission project have issued harsh critiques of PJM’s handling of the solicitation, seeking to persuade the Board of Managers to reject planners’ recommendation that the project be awarded to Public Service Electric & Gas.
In letters to the board, Northeast Transmission Development, a unit of LS Power, and Atlantic Grid Development, whose backers include Google, allege the competition was tainted by favoritism and that the PSE&G project will have difficulty winning siting approval. The challengers also contend the technical design of the winning project is inferior to their own proposals.
Atlantic Grid’s proposal failed to make PJM’s list of finalists. LS Power’s project was the low-cost proposal among the 10 finalists until PJM planners revamped the PSE&G proposal and deemed it equal in cost to LS Power’s at $211 million to $257 million. The changes reduced PSE&G’s price tag by $832 million, a 78% reduction. The estimates do not include an additional $80 million for a static VAR compensator, which PJM added to all of the proposals. (See PSE&G Wins $300M Artificial Island Project.)
In his letter, Northeast Transmission President Paul Thessen said PJM’s cost estimate for his company’s project is too high. He said the company estimates its project at $149 million and will cap its recovery at $171 million, a savings of at least $40 million to $90 million over the PSE&G project.
The board is scheduled to consider the staff recommendation at a meeting July 22.
“After careful evaluation, PJM’s staff concluded that ours was the best proposal. We believe that is the correct choice,” PSE&G spokesman Mike Jennings said in a statement. “We have successfully completed transmission projects in environmentally sensitive areas and performed that work on time and on budget. We are committed to doing the same with this project.”
PJM spokesman Ray Dotter declined to comment on the critiques. “We can say in general that our approach, which was made clear all through the development of our Order 1000 filing and reiterated throughout the Artificial Island evaluation process, is that we would look for the most cost-effective transmission solution,” he said.
Unwarranted Preference
Atlantic Grid said PJM planners gave PSE&G an “unwarranted preference” based on its participation in the Lower Delaware Valley Transmission System Agreement (LDV), a 1977 compact that controls right of way along the recommended project path between the Hope Creek nuclear plant and Red Lion, Del. Other signatories are JCP&L, Delmarva Power & Light, Atlantic City Electric and PECO.
Crediting PSE&G for the LDV right of way ignores the fact that about half the route is over federal and state land, where it may be difficult to obtain siting approval, Atlantic Grid said. In addition, the LDV right of way, the route of an existing 500-kV circuit, will need to be widened by as much as 200 feet in some locations.
Atlantic Grid said the PSE&G project “has a high likelihood of being rejected” by state or federal permitting agencies because it crosses wildlife protection areas and about 59 water bodies and may adversely impact endangered or threatened species. As a result, the ultimate fix “will be substantially delayed because PJM has proceeded down a dead end,” wrote Atlantic Grid President Robert L. Mitchell.
The New Jersey Board of Public Utilities (NJBPU) submitted comments raising the same concerns before planners announced their recommendation last month.
Atlantic Grid said PJM and its engineering consultant, GAI Consultants Inc., failed to seek a pre-application review from the New Jersey Department of Environmental Protection, which could have provided an indication of the project’s chances of winning required permits. “If GAI had followed this process its report might well have raised stronger cautions,” Atlantic Grid said.
Reliability of Design
Atlantic Grid also said the planners’ choice does not provide black start support for Artificial Island and ignores Nuclear Regulatory Commission regulations requiring nuclear plant switchyards be served by two physically independent circuits to minimize the likelihood of simultaneous failure. The PSE&G project would add a 500-kV line paralleling LDV’s existing 500-kV circuit.
Home to the Hope Creek and Salem nuclear plants, New Jersey’s Artificial Island is one of the largest nuclear complexes in the country.
26 Proposals
PJM asked for solutions to a stability problem at the complex last year. Five utilities and three independent developers responded with 26 potential solutions ranging from $100 million to $1.5 billion.
Atlantic Grid’s proposal, which would have buried an HVDC transmission circuit in public road rights of way between Artificial Island and Cardiff, N.J., appears to have been rejected early in the process. PJM cited its $1.01 billion cost and said it failed stability performance tests.
PSE&G, whose sister company PSEG Nuclear LLC operates the Salem and Hope Creek nuclear plants, submitted 14 alternative solutions, more than any other competitor.
One PSE&G proposal, 7K, envisioned a new New Freedom-Deans 500-kV line and a new Salem-Hope Creek-Red Lion 500-kV line at a cost of $1.066 billion.
The 7K project PJM planners recommended last month included several major changes that PJM says reduced the price by more than three-quarters.
Atlantic Grid criticized planners for modifying proposals that initially failed the technical review to allow them to qualify. “Some proposals were modified more than others, and others were not modified at all, raising significant questions about why PJM discriminated in this manner and the fairness of the process,” Atlantic Grid said.
“It appears that PJM took the proposals and then re-engineered a solution it liked best by mixing and matching pieces from different project proposals. The result is that PJM’s recommended 7K Project looks almost nothing like the original 7K proposal submitted by PSE&G.”
PJM Review
PJM planners began reviewing the proposals in July. In October, planners told the Transmission Expansion Advisory Committee they had narrowed their focus to the lowest-cost projects, which proposed interconnecting with facilities in Delaware. They also said they intended to add static VAR compensators to all proposals to provide reactive support.
By February, the focus had narrowed to proposals using two routes to connect to Delaware: a northern path that would add a 17-mile 500-kV line that parallels the existing 500-kV line from Red Lion to Hope Creek, and a southern crossing using a 230-kV circuit. The northern crossings included PSE&G’s 7K proposal; among the southern crossings was LS Power’s proposal, 5A.
By the March TEAC meeting, PJM planners apparently had decided to eliminate the New Freedom-Deans 500-kV line from the PSE&G proposal, showing its cost as proposed reduced to $297 million.
At a special TEAC meeting in May, planners said they also had eliminated a second tie line between the two nuclear plants from proposals by PSE&G and Dominion Virginia Power.
That reduced the estimated cost of the PSE&G proposal by about $43 million, giving it the same range ($211 million to $257 million) planners had assigned to the LS Power proposal, which had previously had been listed as the lowest cost option.
The elimination of the tie line also improved the performance of the PSE&G proposal in the planners’ rankings of the proposals.
PJM presented a chart summarizing its analyses of the proposals, assigning color codes for each of 25 attributes: green (positive or limited impact); yellow (some impact) and salmon (negative impact). RTO Insider summarized the findings by assigning a score of 1 to green, zero to yellow and -1 to salmon.
PSE&G’s 7K proposal scored a 1 out of a possible 25 in its original form but received a 9 when the second tie line was removed — the best of all 12 proposals analyzed. LS Power’s proposal scored a 7, ranking it third. (See Dominion, PSE&G Proposals Gain in Artificial Island Race.)
LS Power contends PJM planners underestimated the cost of the PSE&G proposal. The company said GAI Consultants estimated the cost of the 500-kV line at $5 million/mile while staff estimated only $3.6 million/mile. The consultants included an adder of $1 million/mile to account for construction in wetlands, which LS Power said PJM staff apparently did not consider.
LS Power also complains that PJM gave its proposal no credit for factors favoring its proposal, including rightofway, route diversity, black start, market efficiency, feasibility and system outage requirements.
Order 1000 Precedent
While LS Power wants PJM to accept its cost-capped proposal, Atlantic Grid asked the board to delay a decision until it evaluates the likelihood of the proposals to receive necessary siting approvals.
The challengers said the selection of PSE&G would set a bad precedent for future solicitations under the Federal Energy Regulatory Commission’s Order 1000, which was intended to open transmission development to competition.
“Unfortunately, if this RFP sets the pattern for the future, PJM will discourage participants from spending time, money and engineering resources to develop innovative, well-engineered RFP responses,” Atlantic Grid said.
