The Operating Committee Tuesday postponed a vote on proposals to increase penalties for under-performing synchronized reserve providers.
The committee voted 70-0 to delay the vote until five days after PJM provides members with performance data for their own Tier 2 synchronized reserve resources. PJM’s Stan Williams said PJM should provide the requested data within 10 days.
The representative for Dayton Power & Light Co. initially proposed the vote be delayed until the October OC meeting.
Williams said that an October vote would jeopardize PJM’s hopes of enacting tougher penalties by the end of 2013 — and thereby avoid a mention of the issue for the third year in a row in Monitoring Analytics’ State of the Market report.
Williams’ comment angered Brad Weghorst, of PPL. “Are we going to rush a proposal through just so we can make the State of the Market report?” he asked. “I don’t give a crap” about meeting the report deadline.
The Dayton representative, however, agreed to Williams’ request to amend his motion by calling for a special OC meeting five days after the data is provided.
PJM and the Market Monitor proposed increasing the penalties, saying the current penalty structure is insufficient to ensure compliance.
The current penalty is to take away revenue for the hour when the resource did not perform and also require the resource to provide Tier 2 reserves without compensation when needed for three days. If a resource fails to perform in one hour it doesn’t affect its credit for performing in another hour during the same day.
Because Tier 2 SR calls have declined to about once every 10 days from one in every three days, the three-day penalty has lost its bite. A PJM analysis found that between 2009 and 2012 generators provided only 64% of the megawatts they were assigned while demand response resources provided 53% of assignments.
Second Penalty Option
The second alternative was proposed by Dave Pratzon, of GT Power Group, who represents generation owners. Pratzon said the proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.
PJM shouldn’t switch from a “penalty that’s likely too low to catch people’s attention to a penalty that’s too high,” Pratzon said.
Pratzon said one of the causes of the current performance is that many resource owners may not realize they’re being penalized because the penalties aren’t itemized in their PJM bills.
“I believe there’s a shared interest in improving performance,” Pratzon said. “Are there any bad actors in my generation fleet? If there are, I want to get with the station operators … and improve their performance.”
Another member agreed that PJM’s proposal was overly harsh but said Pratzon’s might be too lenient. He suggested a 25% “adder” to Pratzon’s penalty.
Members Wednesday gave preliminary approval to a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.
The Market Implementation Committee approved the Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm — on which CTS trades will be based. The Markets and Reliability Committee will vote on the measure in a sector-weighted vote as soon as Sept. 26.
The amendment was proposed by a representative of J.P. Morgan Ventures Energy Corp. [Editor’s Note: RTO Insider is prevented from quoting from this representative without his permission due to the Code of Conduct.]
The revised proposal would allow CTS to begin no sooner than September 2014 — later if MRC is not satisfied with the accuracy of the forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application.
Reducing Uneconomic Flows
The new product is intended to improve price convergence between PJM and NYISO by reducing uneconomic power flows. Traders would be able to submit “price differential” bids that would clear when the price difference between New York and PJM exceed a threshold set by the bidder. (See PJM, NYISO Tout New Option to Improve Power Scheduling.) This option would be in addition to two current options: hourly evaluations of traditional wheel-through transactions and intra-hour evaluations of traditional LMP bids and offers.
J.P. Morgan’s amendment commits PJM to provide members with the results of its IT SCED forecasts — previously used only by PJM operations — beginning December 15.
Although PJM will file required tariff changes with FERC in the interim, CTS could not be implemented until the MRC votes to approve the use of the algorithm — a vote that would not occur before the July 2014 meeting. “If [members] are uncomfortable with the forecast we could not move forward with CTS until we have an improved” forecast, endorsed by MRC, explained PJM’s Stan Williams. [See table, CTS Implementation Timeline]
A Natural Death
The vote came after a lengthy discussion.
One member asked whether PJM would make public the forecasting model. “We’re trying to understand how to IT SCED comes up with these prices,” he said.
Adam Keech, PJM director of wholesale market operations, said PJM could not disclose the algorithm, which was developed by Alstom Holdings, because of intellectual property concerns.
Another member noted that CTS trades are voluntary and will supplement – not replace – current scheduling options. “If people don’t have confidence in it this dies a natural death because nobody uses it.”
MIC chair Adrien Foley rejected several members’ suggestions that the proposal was being rushed, noting that the committee had been discussing it since July and held a special meeting on the topic Sept. 10.
During the lunch break, PJM officials negotiated with J.P. Morgan on changes to the proposal. (See redlines in the proposal.) After lunch, Foley announced that the RTO and the sponsor had reached a deal.
Notice of Changes
In addition to allowing members to validate the IT SCED forecasts before CTS takes effect, the agreement requires PJM to provide 90 minutes’ notice before making changes to IT SCED that “would have any effect on” forecasts.
Keech balked at J.P. Morgan’s original proposal, which would have required 30 days’ prior notice. Keech said it could prevent operators from making timely changes needed to ensure smooth operations. “You’re handcuffing our ability to fix things that may have nothing to do with this issue,” Keech said. “…If I see a problem, I need to act today.”
The agreement also requires PJM to consider “appropriate” balancing operating reserve charges for CTS transactions in the Energy Market Uplift Senior Task Force (EMUSTF), and to assess transmission service charges on CTS trades “in a manner that is consistent with the transmission service charges for all cross-border transactions.”
Vote Tally
The proposal was approved by acclimation with 43 abstentions and 17 votes in opposition. Edison Mission Marketing and Trading was among those voting no. Those abstaining included FirstEnergy, NRG Energy, Old Dominion Electric Cooperative, DC Energy, Noble Americas, the PJM Public Power Coalition and the PJM Industrial Customer Coalition.
PJM has added more granularity for the Mid-Atlantic area in its load forecasting file. The Mid-Atlantic area is now represented with zonal forecasts for PSE&G (e.g. PSE&G/MIDATL), PECO, PPL, UGI, BG&E, JCP&L, METED, PENELEC, PEPCO, AE, DP&L, and RECO.
The zonal forecasts are apportioned based on the zonal percentage of Mid-Atlantic load in that hour on a similar day (temperature and load) or the prior day’s loads.
The Operating Committee last week endorsed revised charters for the System Information and Dispatcher Training subcommittees.
System Information Subcommitee
Reason for change: Introduction of synchrophasor technology systems to PJM.
Impact: Adds language to core competencies: “SIS members should be knowledgeable in both Information Technology and the generation, transmission and economic operation of the electric power grid. The member should be a leader in either the operations or markets area of their company.”
SIS members are appointed by their Operating Committee member.
Dispatcher Training Subcommittee
Reason for change: The charter was never updated after the subcommittee was upgraded from a task force.
Impact: Removes outdated references; notes that subcommittee reports to Operating Committee.
PJM cut loads in Indiana, Michigan, Ohio and Pennsylvania Tuesday as 90-degree temperatures pushed loads to the highest ever for September, stressing the grid at a time when much generation and transmission was offline due to planned outages.
Load peaked at 144,370 MW Tuesday and would have been higher Wednesday but for demand response. PJM said it tapped almost 6,000 demand response resources Wednesday –- an all time record, equivalent to five nuclear plants –- limiting the day’s demand to 142,071 MW.
Last year, September loads never exceeded 130,000 MW.
Tuesday’s peak load was almost 3% above the RTO’s 140,500 MW forecast. “We under-forecast by quite a bit,” Adam Keech, director of wholesale market operations, told the Market Implementation Committee in a briefing Wednesday.
The large change in temperatures from Monday to Tuesday made load forecasting more difficult, officials explained yesterday. “We look closely at the patterns of the previous day’s temperatures and load when forecasting for a day, and, when they greatly differ, it’s much more difficult to estimate the day’s load,” said PJM spokesman Ray Dotter.
In response to a question from the Michigan Public Service Commission at the MIC meeting, PJM officials acknowledged they had ordered Indiana Michigan Power to shed load. But they provided members no specifics and did not mention that the RTO had cut loads in four states.
That disclosure came when PJM issued a press release later Wednesday, in which it said that the “unusual, extreme heat combined with local equipment problems to create emergency conditions in Indiana, Michigan, Ohio and Pennsylvania. “
The RTO said it was forced to cut load in those areas “to avoid the possibility of an uncontrolled blackout over a larger area that would have affected many more people.”
“We sincerely regret that conditions on the grid yesterday required us to call for emergency reductions in consumer demand,” the release quoted PJM CEO Terry Boston.
The initial statement provided no details on the location, size or duration of the cuts. PJM told RTO Insider Thursday the cuts totaled about 150 MW and ranged from one to eight hours: the Erie South substation, in Penelec, was off for about 6 hours; the Tod substation, in FirstEnergy’s ATSI zone, about 1.5 hours; the Summit substation, in AEP’s Indiana Michigan Power, 1 hour and I&M’s Pigeon River substation, about 8 hours.
According to local media reports, Indiana Michigan Power (I&M) reported more than 3,300 customers in Northwest Fort Wayne lost power at 7:15 p.m. Tuesday, with power was restored by 8:30 p.m.
I&M also cut power to about 1,072 customers in White Pigeon, Michigan, beginning about 1 p.m. Tuesday. All customers were returned to service by 9 p.m.
Wednesday, PJM called on emergency demand response but did not issue any additional load shed orders.
PJM issued a hot weather alert in the west beginning Monday. On Tuesday, it deployed emergency demand response in ATSI from 15:50 to 21:30. Keech said DR set marginal prices at $1,800/MWh “for the better part of peak.”
PJM also had an unusually long spin event — about one hour — because of difficulty maintaining its Area Control Error (ACE). “We under-forecast load… we had to make it up somewhere,” Keech explained.
The Northeast Power Coordinating Council (NPCC) responded to a call for shared reserves with 800 MW.
Exelon’s 3,586 MW Braidwood 1 nuclear plant in Braceville, IL was one of four PJM-area nuclear plants offline for maintenance during the unexpected September heat spike. (Source: NRC)
Keech said the Cleveland interface was a major challenge with multiple transmission lines tripping.
Wednesday brought a maximum generation alert for the entire RTO, with PJM activating emergency DR in both the AEP and ATSI zones. Keech noted that forecasts called for thunderstorms that had the potential of quickly dampening load.
“If the storms come in during the peak we potentially get stuck holding the bag for emergency DR,“ Keech said.
Officials did not provide members any details about the amount of transmission and generation out of service for maintenance. However, the Nuclear Regulatory Commission reported that four nuclear plants in or near PJM – Exelon’s Peach Bottom 3 and Braidwood 1; Dominion’s North Anna 1, Detroit Edison’s Fermi 2 — were out of service today.
The Energy Information Administration last week highlighted PJM’s response to the retirement of coal-fired generation in the ATSI zone in northern Ohio.
FirstEnergy’s retirement of 1,400 MW of generation in 2012, and planned closure of an additional 885 MW in 2015, will reduce generating capacity in the ATSI zone by 21%. But PJM was able to compensate with transmission, EIA noted in its Today in Energy feature, because of its 29% reserve margin.
“In a highly populated area that requires significant backup power in reserve, it may be more cost-effective to upgrade the transmission system” than build new generation, EIA said.
(Source: Energy Information Administration)
In May, the PJM Board of Managers approved more than two dozen transmission projects in ATSI to address the retirements, at a projected cost of about $1 billion. Replacing FE’s coal generation with 2,285 MW of new advanced combined cycle units would have cost almost $2.3 billion, according to EIA’s estimated overnight capital cost of $1,003/kw.
Capacity prices in the ATSI region, which cleared at about $350/MW-day in the 2015-16 auction conducted last year, fell to less than $100/MW-day in the 2016-17 auction, conducted after approval of the transmission upgrades.
The projects include the new Toronto-Harmon 345 kV line ($218 million) and the Mansfield-Northfield 345 kV line ($184.5 million).
Commonwealth Edison’s smart meters are not to blame for overheating and fires that occurred in a pilot program. State regulators said the problem was loose connections and corrosion in customer-owned casings. Three smart meters caught fire during a 2010 pilot program, in which ComEd installed 130,000 smart meters.
Meanwhile, ComEd began installing smart meters for 60,000 customers in Chicago’s western suburbs last week. The company expects to complete the installations by the end of the year and hopes to switch all of its 4 million customers to the devices by 2021.
Harlan County recorded the state’s highest unemployment rate in July at 17.2% while neighboring Bell County saw its rate hit 14.5%. “The majority of the layoffs have been coal mining jobs or jobs related to the mining field,” said one official. “In Bell and Harlan counties, coal impacts almost every business and almost every family in some way.”
Eastern Kentucky lost more than 4,000 coal jobs in 2012 as production in the region fell to its lowest levels since 1965, according to the Kentucky Department of Energy Development and Independence.
Some in Montgomery County are criticizing Gov. Martin O’Malley’s appointment of a former PSEG executive to the Public Service Commission, saying the agency needs a stronger consumer perspective. Anne E. Hoskins of Baltimore, was a senior vice president of public affairs and sustainability for PSEG.
The Public Service Commission agreed Wednesday to give a wind power developer until the end of 2014 to begin work on a 25-turbine wind farm on Dan’s Mountain in Allegany County.
Laurel Renewable Partners, developer of the project, said it was unable to meet the PSC’s original September 2013 deadline due to financial difficulties and restrictive local zoning regulations. The company says Exelon Corp. has agreed to fund the project.
Jersey Central Power & Light is partnering with a local electrical workers’ union to quicken system restoration following storms. Members of IBEW Local 102 will supplement utility personnel in providing damage assessments for downed wires and other hazards, freeing up JCP&L crews to do major restoration work. Union members may also be used to repair damaged connections at homes, hook up generators and help at water distribution stations.
The company said it expects the JCP&L-IBEW Emergency Response Team program — the first of its type in New Jersey — to be adopted by other utilities.
Dominion, Solar Developer Dispute `Avoided Cost’ Calcs.
Dominion North Carolina Power asked the state Utilities Commission to reject a request by the developer of a 20 MW solar project for a higher price for its power. Dominion said it is willing to sign a 15-year contract with SunEnergy1 to buy all the power produced by the $50 million solar project in Scotland Neck but not at the price the developer is seeking. The dispute centers on how Dominion computed its “avoided cost” for the power.
State regulators’ investigation of the electricity market in Ohio has focused too much on ways to help energy companies and has largely ignored consumer issues, according to a coalition of consumer groups. Those groups said consumers have little access to information about how to choose suppliers and too little protection against misleading solicitations. State regulators say that consumer issues are being addressed in a separate case.
More than 60,000 Facebook users reportedly signed a pledge not to switch to FirstEnergy Solutions for electricity service. A coalition of environmental groups organized the online campaign in response the company’s push to change Ohio’s energy efficiency law.
FirstEnergy is trying to attract central Ohio customers who now get their electricity service from incumbent American Electric Power. In April, a FirstEnergy executive told an Ohio Senate committee the state needs to change its energy efficiency policy, claiming it is harming electricity customers and the state’s economy.
Anti-Fracking Group Seeks Drilling Ban in Youngstown
Members of a group seeking to ban fracking in Youngstown collected enough signatures for the charter amendment to be on the Nov. 5 ballot, but a pro-business group that helped defeat a similar anti-fracking measure in May is challenging the legality of the proposal.
Meanwhile, new research concluded that a fracking waste disposal well linked to 11 earthquakes that rocked the Youngstown area was likely also responsible for at least 98 additional temblors that were too weak for people to notice. The results were published in the Journal of Geophysical Research: Solid Earth.
U.S. Rep. Allyson Schwartz joined two other Democratic gubernatorial hopefuls in calling for a 5% severance tax on Marcellus Shale natural gas production. Schwartz said she would invest the tax revenues — estimated at $612 million this year — in education and transportation infrastructure.
The tax would be in addition to an impact fee enacted last year. The Democrats are vying to face off against Republican Gov. Tom Corbett, who opposes additional taxes on the industry.
PJM Meets State over Plant Closures; Neighbors Sue
State officials met with the PJM Interconnection in an effort to prevent FirstEnergy Corp. from its planned Oct. 9 closure of the Hatfield’s Ferry and Mitchell power stations. PJM asked the company in early August to postpone the shutdown, saying it needed more time to complete transmission upgrades to maintain reliability in the plants’ absence.
Several state legislators and representatives of the governor’s office met with PJM at the Public Utility Commission’s office in Harrisburg to brainstorm on ideas to get FirstEnergy to reconsider its plans.
Meanwhile, neighbors of Hatfield’s Ferry filed a class action suit over particulate emissions from the coal-fired generator. The suit, filed in U.S. District Court in Pittsburgh, seeks to represent more than 1,000 residents living within a 1.5-mile radius of the plant.
West Penn Power energized a new 138-kilovolt (kV) transmission line connecting a substation near Kirby, Pa., with a substation in Monongalia County, W. Va. Both substations were expanded and reconfigured to accommodate the new line. While the majority of $20 million project is located in the West Penn Power service area, the West Virginia portion of the line is expected to benefit customers of Mon Power, another FirstEnergy subsidiary.
West Penn Power plans to spend about $110 million on reliability projects in 2013.
The state Department of Environmental Protection is conducting a study of radioactive shale gas waste to determine any risks involved in its transportation or disposal. Nearly 1,000 trucks hauling 16,000 tons of Marcellus Shale waste were stopped at Pennsylvania landfill gates after tripping radioactivity alarms last year. After testing, more than 600 tons were shipped to out-of-state landfills designed to dispose of radioactive materials.
Celanese Spending $150M to Switch from Coal to Gas
Celanese Corp. has begun work on a $150 million project to replace its coal-fired boilers with ones fueled by natural gas. The project, prompted by federal air quality regulations, will include a 16-mile pipeline to connect the company’s plant near Narrows, Va., to a natural gas supply in West Virginia.
State and local governments agreed to contribute $7 million in grants and tax breaks to keep the plant — Giles County’s largest employer with more than 1,000 workers — from moving. The plant, which opened in 1939, produces acetate tow, a material with various industrial uses.
The West Virginia Public Service Commission has approved a rate decrease for Appalachian Power Co. and Wheeling Power Co. customers. The PSC Friday issued an order reducing the Expanded Net Energy Cost (ENEC) rates for customers by more than $50 million due to lower coal costs.
Limestone Conveyor at Longview Power Plant (Source Mascaro Construction Co.)
Longview Power LLC, developer of a $2 billion coal-fired power plant in north-central West Virginia, filed for Chapter 11 bankruptcy protection but said neither workers nor customers will be affected in the short term. Longview said that it will continue operations while negotiating with lenders.
Dominion will move its office in Clarksburg to a more modern 100,000 square foot facility in Bridgeport. About 300 Dominion employees will be affected by the move, which is targeted for late 2015.
Seneca Pump hydro plant in Warren, PA (Source: FirstEnergy)
FirstEnergy Corp. asked the Federal Energy Regulatory Commission for approval to sell 11 hydroelectric power stations in Pennsylvania, Virginia and West Virginia to Harbor Hydro Holdings, LLC, a subsidiary of LS Power Equity Partners II, LP.
The hydro projects, totaling 527 MW, represent less than 3% of FirstEnergy’s total generation. They are:
Seneca Pumped Storage (451 MW) in Warren, Pa.;
Allegheny Lock & Dam 5 (6 MW) in Schenley, Pa., and Allegheny Lock & Dam 6 (7 MW) in Ford City, Pa.;
Lake Lynn (52 MW) in Lake Lynn, Pa.;
Millville (3 MW) in Millville, W. Va.;
Dam 4 (2 MW) in Shepherdstown, W. Va., and Dam 5 (1.2 MW) in Falling Waters, W.Va.;
Warren (750 kW) in Front Royal, Va.;
Luray (1.6 MW) in Luray, Va.; and
Shenandoah and Newport (860 kW and 1.4 MW, respectively) in Shenandoah, Va.
The company announced in February plans to sell up to 1,180 MW of hydroelectric generation acquired in the company’s merger with Allegheny Energy. But a FirstEnergy spokeswoman told RTO Insider the company is not “actively seeking” buyers for its remaining hydro assets: Allegheny Generating Co.’s 1,200 MW of the 3,000 MW Bath County Pumped-Storage Hydro facility in Warm Springs, Va., and Jersey Central Power & Light’s 200 MW of the 400 MW Yards Creek Pumped-Storage Hydro facility in Blairstown, N.J.
FuelCell Energy, Inc. announced a co-marketing agreement with NRG Energy for the company’s distributed generation power plants.
NRG will market the power plants to its customer base, offering a financing option in which NRG will purchase and own the power plant and sell power and heat to the end-user. The agreement also allows NRG to purchase power plants for its own portfolio. FuelCell Energy will operate and maintain the power plants owned or sold by NRG.
FuelCell Energy saw its stock jump 15 percent on the announcement Sept. 5. The company’s power plants are installed at more than 50 locations in the U.S., South Korea, Germany and the United Kingdom.
NRG Energy announced its entry into the retail electric business with a new company that will compete for residential customers in the Philadelphia region. NRG Residential Solutions will offer a choice of plans “emphasizing choice, control, rewards or innovation.” The company said it plans to expand throughout Pennsylvania, New Jersey, Maryland and the District of Columbia.
FirstEnergy Nuclear Operating Company, a subsidiary of FirstEnergy Corp., named Ernest J. Harkness site vice president at the Perry Nuclear Power Plant in Perry, Ohio. Harkness was previously site vice president at Exelon Corp.’s Oyster Creek Generating Station in Forked River, New Jersey. He replaces Vito Kaminskas, who is retiring.
Duke Energy named Brian Savoy vice president, controller and chief accounting officer. He replaces Steve K. Young, who became executive vice president and chief financial officer on Aug. 6. Savoy, 38, has served as director of financial forecasting since 2012 and is a former vice president and controller of the company’s commercial power segment.
The company also named Bill Currens vice president, investor relations. Currens replaces Bob Drennan, 65, who will retire Dec. 31.
The Nuclear Regulatory Commission Friday cited nine PJM plants for additional scrutiny in its mid-year gradings of the nation’s nuclear fleet.
The NRC grades each reactor based on data submitted quarterly by plant operators (“performance indicators”) and inspections by resident inspectors and regional staff. Its mid-year assessment places all operating units within one of four levels, with the agency’s scrutiny increasing as plant performance declines. (See sidebar: NRC Plant Rating Methodology.)
Eight PJM reactors were named among 17 nationwide in the second highest category and will undergo additional inspections because of items of low safety significance: FirstEnergy’s Beaver Valley 1 and 2 (Pa.) and Davis Besse (Ohio); PPL’s Susquehanna 2 (Pa.), and Exelon’s Three Mile Island 1 (Pa.), Dresden 2 and 3 (Ill.) and LaSalle 2 (Ill.).
In addition, FirstEnergy’s Perry 1 plant in Ohio was among eight reactors cited for a “degraded level of performance,” the third performance level.
The agency said the Perry plant and the Beaver Valley units resolved their issues after the close of the mid-year review and are now in the highest performing level, which are subject to only “baseline” inspections. The agency gave top grades to 75 reactors in the mid-year assessment for the period ending June 30.
One reactor, Browns Ferry 1 in Alabama, is in the fourth category because of a “high significance” safety finding.
In addition, the NRC has shut down the Fort Calhoun plant in Nebraska due to significant performance issues. It is in a special NRC oversight program and did not receive a mid-cycle assessment.
(Source: NRC)
Two other plants, Crystal River 3 and Kewaunee, entered decommissioning during the first half of the year and are no longer considered operating reactors.
Dominion Virginia Power last week won the rights to develop Virginia’s “Wind Energy Area,” nearly 113,000 acres of Atlantic Ocean with the potential to support 2,000 MW of offshore wind generation. But Virginia’s largest utility is making no promises that it will exploit the resource.
“Offshore wind has the potential to provide the largest, scalable renewable resource for Virginia,” the company said in a statement after the auction, “if it can be achieved at reasonable cost to customers.”
That’s a big “if.” The company’s proposed Integrated Resource Plan, filed Aug. 30 with the Virginia State Corporation Commission, commits it to developing only a 12 MW offshore demonstration project. The base 15-year plan, which commits virtually all of its new generation to natural gas, ranked offshore wind as the most expensive of the non-dispatchable resources the company considered, far more expensive than solar or onshore wind.
Dominion estimated a plan incorporating up to 1,600 MW of offshore wind would cost about 14% more than its base plan. This includes an assumption by Dominion that a carbon tax will be enacted by 2023, increasing the cost of generating power with coal and natural gas.
(Source: Energy Information Administration)
The Energy Information Administration estimates the levelized cost of offshore wind at $221/MWh (2011 dollars), more than twice the $87/MWh cost of onshore wind. By comparison, EIA estimates the cost of power from new natural gas-powered combined cycle plants favored by Dominion at $66/MWh.
No Renewable Incentives
The high costs will be a particular challenge in Virginia. The state does not have a mandatory Renewable Portfolio Standard, and unlike Maryland and New Jersey, is not offering any subsidies to encourage offshore wind developers. It also does not allow retail choice, which could create a niche for a green alternative. (See previous coverage: PJM States Seek ‘First Mover’ Status.)
Dominion outdueled competitor Apex Virginia Offshore Wind, LLC in six rounds of bidding conducted by the Interior Department’s Bureau of Ocean Energy Management (BOEM). Six other companies that were prequalified for the auction chose not to bid. One of them, Iberdrola Renewables, told RTO Insider it decided to focus on bringing its pipeline of “more competitively priced” onshore wind projects to market.
Dominion’s $1.6 million bid won it the rights to 112,799 acres on the Outer Continental Shelf, 23.5 nautical miles off Virginia Beach. Assuming it passes an antitrust review by the Justice Department, the company will have five years to submit a Construction and Operations Plan for BOEM’s approval. Including review by state rate regulators, Dominion said it will be a decade before the first turbine could be installed.
Wind Backers Disappointed
Dominion’s victory was a disappointment to environmentalists. Beth Kemler, Virginia State Director at the Chesapeake Climate Action Network, said the company’s IRP “doesn’t leave us with high hopes for Dominion’s speedy development of this clean energy resource.”
“While Dominion came out on top …that unfortunately doesn’t guarantee that the company will actually erect a single turbine. The company could rent the wind energy area for years without moving forward with any development, preventing a more eager company from doing so,” she said.
Dominion spokesman Dan Genest noted that Dominion cannot add new generation without approval of Virginia regulators, who must judge it “prudent.”
“Anything we present as a generation project has to meet the price test,” he said. “To say we’re going to build wind at any cost — the state corporation commission is not going to allow us to do it.”
Genest said the purpose of the company’s demonstration project is to “find ways to make [offshore wind] affordable.”
Demonstration Project
The project, two six-megawatt turbines, will test the use of “twisted jacket” foundations that offer the strength of traditional structures but use substantially less steel. It was one of seven projects awarded $4 million each in federal matching funds to explore ways to lower costs of offshore wind.
Chesapeake Action’s Kemler said another bidder that is not a cost-of-service utility might be willing to develop the site as a merchant project. Other offshore projects under development in Rhode Island, Massachusetts, New Jersey and Maryland hope to finance them through state subsidies, purchase power agreements and the sale of credits tied to mandatory Renewable Portfolio Standards.
Although Virginia has no mandatory RPS, Dominion says it will meet a voluntary goal to obtain 15% of its power from renewables by 2025. Excluding pump storage, renewables represent 3% of Virginia Power’s capacity.
“The legislative climate in the Northeast is a lot friendlier to renewables,” than Virginia, Kemler acknowledged. “But there are certainly plenty of states in PJM that have mandatory RPSs” that might be buyers of offshore wind.
Integrated Resource Plan
Virginia law requires utilites’ Integrated Resource Plans to “promote reasonable prices, reliable service, energy independence, and environmental responsibility.”
Dominion’s recommended expansion plan predicts annual increases in peak demand of 1.6% through 2028. It’s base “least-cost” plan proposes that the company add up to 7,060 MW of new gas-fired generation and 59 MW of solar and biomass, with 544 MW of demand-side management. Also included are PJM market purchases representing 127 MW of capacity and 12% of energy.
In addition, the company developed a higher-cost, lower-emission “fuel diversity” plan that could be needed to respond to potential federal rules restricting greenhouse gases.
It would eliminate one 1,375-MW combined cycle plant, and add 1,453 MW of nuclear power — a third unit at the company’s North Anna facility. Renewables are limited to 220 MW of solar, 247 MW of onshore wind and the 12 MW offshore wind demonstration project. PJM market purchases would increase to 173 MW of capacity.
The company notes that its onshore wind assets are limited to three mountaintop locations in western Virginia. By contrast, the National Renewable Energy Laboratory estimates Virginia has a “technical potential” of 89 GW of offshore wind capacity.
NREL’s estimates don’t consider economic or market constraints that will reduce actual renewable generation. The 2,000 MW “Wind Energy Area” was mapped out by BOEM to avoid conflicts with other ocean uses such as commercial fishing and shipping traffic.
