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.
Members approved yet another initiative to address reliability concerns over gas-fired generators, agreeing to consider changes to the way such units submit energy and capacity market offers.
Under a problem statement approved by the Market Implementation Committee Wednesday, members will consider ways to reduce the confusion that occurred on the coldest days of last winter, when some gas-fired generators were unable to obtain fuel, some claimed costs above the $1,000/MWh offer cap and others ended up with “stranded” gas after PJM cancelled plans to dispatch them. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)
The effort will attempt to design rules that allow generators to submit offers that better reflect often volatile natural gas prices. Among potential changes: allowing generators to change their energy market offers during the operating day and submit differing hourly offers in the real-time market, as the New York ISO allows.
Carl Johnson, representing the PJM Public Power Coalition, expressed concern that stakeholders’ multiple gas-electric coordination initiatives could result in changes whose interactions are not well understood. “We have, at my count, six problem statements … on gas issues,” he said. “I’m concerned as we march forward … how these timelines will work together.”
Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS), also expressed concern. “The expectation for compromise gets less and less as you get more and more complex,” he said.
John Horstmann of Dayton Power & Light Co. suggested the issue could be handled by one of the groups already dealing with gas-electric issues. PJM staff agreed to review work assignments and make a recommendation at next month’s MIC meeting, when stakeholders will consider a proposed Issue Charge.
PJM capacity prices would increase sharply but reliability would not be threatened if a recent federal court ruling eliminated demand response from wholesale markets, according to a new report by the Independent Market Monitor.
Market Monitor Joe Bowring said the sensitivity analysis released last week is intended to help stakeholders evaluate the impact of the May 23 ruling by the D.C. Circuit Court of Appeals that sharply restricts the Federal Energy Regulatory Commission’s jurisdiction over demand response compensation. (See DR’s Future Unclear Following Court Ruling.)
Revenue in the May base residual auction would have more than doubled to $16.86 billion from $7.5 billion if no DR or energy efficiency cleared, the analysis found. Cleared resources would have dropped by 3,290 MW, reducing reserves to 2% above the Installed Reserve Margin (IRM) from 4.4%. Bowring said the analysis included energy efficiency as “another form of DR,” which could be vulnerable under the court ruling.
Disruptive Ruling
On July 7, PJM joined FERC in asking the Court of Appeals to reconsider its ruling. “Extricating demand response from markets in which it has had years to integrate will be inherently disruptive and will inevitably raise countless unforeseen complications,” PJM said. While Order No. 745 was limited to economic demand response in daily energy markets, its implications are “potentially boundless.”
PJM’s petition overstates the impact of DR on reliability and understates the ability of PJM markets to respond, Bowring said in an interview Friday.
“If there’s a decision to eliminate [DR and EE] the market will adapt,” Bowring said. “Once you allow for other offers to respond to all this we would expect the prices to equilibrate — balance out — to the cost of new entry.”
Capacity prices doubled for much of the RTO in May’s base residual auction following rule changes that reduced the volume of limited DR and external generation that could clear.
Annual resources cleared at $215/MW-day for the PSEG zone, while the rest of the RTO cleared at $120/MW-day, about one-third of the $351 net cost of new entry (net CONE).
2.5% Holdback
The IMM’s study also looked at the potential impact of Bowring’s recommendation to eliminate a rule that reduces the volume of capacity resources procured in the BRA by 2.5%. Stakeholders last year rejected calls to eliminate the 2.5% holdback, which is intended to be filled by short lead-time resources procured in incremental auctions closer to the delivery year.
Had the holdback been eliminated along with DR and EE for the May BRA, capacity revenues would have more than tripled to $23.87 billion, or $396/MW-day, 13% above net CONE. The quantity of resources acquired would fall but remain sufficient to meet the IRM, the Monitor’s analysis found.
With the removal of DR and EE and the elimination of 2.5% offset “prices would have risen to greater than net CONE but less than the maximum price [1.5 times net CONE] and PJM’s reliability target would have been maintained,” the Monitor said.
The analysis assumed that all other variables are held constant, meaning that the real impact would likely be less because additional generation resources would have cleared the auction. “In the absence of demand side resources, some generating resources that retired in prior years might not have retired, and some new generation resources that did not clear in prior years would have cleared and both would have affected prices in subsequent auctions.”
The Monitor made no predictions on where prices would settle.
Concerns over Court Ruling
The D.C. Circuit ruled 2-1 that FERC’s Order 745, which requires PJM and other RTOs to pay DR full locational marginal prices (LMP), violates state ratemaking authority.
In its petition seeking a rehearing, PJM cited “the considerable uncertainty this decision has engendered” for PJM, which has used DR since 2000. Although PJM opposes Order 745’s equal-compensation mandate, General Counsel Vince Duane said the RTO sought rehearing because of concerns over the loss of DR.
PJM said the ruling appears to “forbid any compensation (regardless of the level) to economic demand response from the wholesale daily energy markets, not just the compensation change addressed by Order No. 745.”
“PJM does not have good options for replacing demand response capacity commitments on very short notice for the current summer, and replacing demand response capacity commitments for the next three summers (to the extent they even can be fully replaced) would likely be very costly,” PJM said.
The filing cited DR’s role in maintaining reliability during last September’s unexpected heat wave, when PJM was forced to shed load in some areas and during the arctic cold in January, when it “received more megawatts as load reductions than it could obtain as generation from all but the very largest generating stations.”
The RTO called for load reductions on 13 days in 2013. DR providers are committed to provide more than 8,000 MW of load reduction this summer and more than 10,000 MW for the summers of 2015-2017.
PJM said the loss of the wholesale markets might result in the elimination of many DR resources because the retail market cannot compensate DR for providing regulation, spinning reserves and day-ahead scheduled reserves, as PJM does.
In addition, it is unclear how DR procured through state-run retail processes could compete on price with generation procure in wholesale markets, PJM said. “There should be no mistake that pulling voluntary demand resource offers out of the grid operators’ single-clearing price markets will significantly reduce competition in those markets.”
This would contradict Congress’ direction in the 2005 Energy Policy Act to encourage demand response and eliminate “unnecessary barriers to demand response participation in energy, capacity, and ancillary service markets,” PJM said.
PJM officials said last week they have acquired sufficient new black start capacity to replace coal-fired units that will retire over the next year due to environmental rules.
PJM’s black start capacity will decline to 8,070 MW (150 units) from 8,720 MW (195 units), PJM’s Dave Schweizer told the Market Implementation Committee Wednesday.
Schweizer said PJM will have adequate supplies despite the reduction because of a redefinition of “critical load” and a rule change allowing units in one zone to provide service to others.
The redefinition — which will include units with hot start times of four hours or less — will increase the number of critical load units to 600 from 475 while reducing the total capacity to 2,910 MW from 4,780 MW.
PJM’s black start costs for 2016-17 will total more than $72 million, a 1.8% increase over 2015-16, according to an analysis by the Independent Market Monitor. Some zones, such as Dominion (+39%) and DPL (+27%), will see large increases, while others, such as Commonwealth Edison (-30%), will see sharp drops.
The RTO completed a solicitation for new black start resources because the Environmental Protection Agency’s Mercury and Air Toxics rule (MATs), which takes effect next year, will result in the shuttering of dozens of coal-fired plants.
PJM will attempt to win stakeholder approval for limited changes to the compensation rules for black start units and for a plan for selecting “backstop” resources for regions that fail to secure service through competitive solicitations.
In February, stakeholders rejected two proposals that would have boosted payments to existing black start units by at least 40%. On July 31, the Markets and Reliability Committee will consider smaller compensation changes. (See PJM to Seek Smaller Black Start Changes.)
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.
