The Federal Energy Regulatory Commission last week approved Duke Energy Progress’ $1.2 billion purchase of 700 MW of generation from the North Carolina Eastern Municipal Power Agency.
The deal will give Duke NCEMPA’s share of the Brunswick and Shearon Harris nuclear plants and the Mayo and Roxboro coal plants, generators that Duke jointly owned with NCEMPA.
Duke and NCEMPA agreed to the sale in late July and submitted it for FERC approval on Oct. 10. (See NCEMPA to Sell 700 MW of Generation to Duke.) There were no protests opposing the deal or comments asking for any conditions. In its order, the commission said it had no concerns about adverse effects on horizontal or vertical competition resulting from the deal.
The deal must still be approved by the Nuclear Regulatory Commission and regulators in North and South Carolina. Company officials are targeting to close in the third quarter of 2015.
According to Duke, NCEMPA members have accrued more than $2 billion in debt and its customers’ rates have increased since the 1980s. While FERC did not say whether it expected rates to go down, it found that rates would not be adversely affected by the deal. Duke will collect $343 million through rates, FERC said, but the company included a five-year hold-harmless commitment that it would not increase rates as part of the deal. NCEMPA members, and their customers, would still be on the hook for paying off the remaining debt, but the sale will significantly lessen it.
After breezing through regulatory approvals by Virginia and the Federal Energy Regulatory Commission, Exelon’s $6.8 billion acquisition of Pepco Holdings Inc. (PHI) is starting to run into some headwinds.
Citing doubts about Exelon’s claimed economic benefits, the staff of the Maryland Public Service Commission said the company should provide $167 million in credits to customers, an increase of two-thirds over the $100 million the company offered.
And last week, the Maryland Office of People’s Counsel urged the commission to reject the deal.
“There is no doubt that this acquisition is a boon to PHI shareholders, but it offers nothing to Maryland’s utility customers,” People’s Counsel Paula M. Carmody said. “While Exelon has provided a ‘checklist’ of purported benefits, including better reliability, to customers and the state, OPC has determined that they are either non-existent or woefully deficient.”
The Chicago-based energy giant still needs approval from Maryland, D.C., Delaware and New Jersey, in addition to the U.S. Department of Justice.
Like several groups that have filed comments with the PSC opposing the acquisition, Carmody is concerned about the size of the company that would result.
“Exelon already owns [Baltimore Gas and Electric], but this acquisition would allow Exelon … to control electric utilities serving 80% of Maryland’s electric customers,” she wrote. “Such an acquisition would allow Exelon to exercise undue influence and control over regulated electric service and retail electric company policies in most of the state of Maryland and much of the footprint in the PJM wholesale market area.”
Market power issues are at the forefront of other interveners’ concerns, including PJM’s Independent Market Monitor, Joe Bowring. Repeating concerns he expressed during the FERC approval process, Bowring said mitigation measures should be taken to keep the combined companies from exerting undue influence.
“The proposed merger raises potential vertical and horizontal market power issues,” Bowring wrote in a letter to the PSC last week.
Bowring recommended requiring the companies to agree to remain in PJM and to permit independent third-party interconnection studies. RTO Insider reported last week that the Department of Justice is investigating the interconnection process in PJM’s MAAC sub-region as part of its review of the merger. (See DOJ Probing Interconnection Process in Exelon-Pepco Merger.)
The Monitor also said Exelon should agree to a review of ratings of all elements of the combined transmission systems and a regular process for reviewing and updating transmission limits.
FERC approved the acquisition without requiring any of Bowring’s proposed mitigation measures. (See FERC Approves Exelon-Pepco Merger.)
Bruce Burcat, executive director of the Mid Atlantic Renewable Energy Coalition (MAREC), said that even mitigation measures wouldn’t keep Exelon from growing too powerful for the market.
“The size and scope of this merger in and of itself raises a lot of angst for MAREC as we are very troubled by the ability of this huge utility to dominate markets,” Burcat wrote the Maryland commission last week. “I am not sure that there is a sure way to completely mitigate or even anticipate the impacts … that the combination of these companies will present to regulators, competitors and most importantly ratepayers.”
Like many other groups, MAREC has also filed opposition briefs with regulatory agencies in D.C., Delaware and New Jersey.
While the Maryland PSC staff report didn’t urge rejection of the merger, it said that Exelon’s claims of economic benefits to the state was “deeply flawed” and said that the deal could result in job-loss impacts totaling up to $309 million.
In addition to the $100 million in customer credits, Exelon has promised to continue the charitable giving that Pepco did, to the tune of $50 million over the next 10 years.
Exelon spokesman Paul Adams acknowledged that not all parties are satisfied with what the company is offering but said the acquisition is a good deal for the entire territory.
“As part of this [PSC review] process, we are open to feedback and discussions with all stakeholders,” he said in a prepared statement. “We believe that the facts — which are available in the testimony we’ve filed with the commission and other information we have provided to the parties through the regulatory process — will show that this merger is in the public interest and will benefit customers and the community.”
Exelon has gathered some allies in Maryland. In October, the president of the Montgomery County Council, Craig L. Rice, wrote the PSC to say he believes that “the combination of these two companies is clearly in the public interest and will benefit Pepco customers, Montgomery County and the State of Maryland.”
Brien Poffenberger, CEO of the Maryland Chamber of Commerce, expressed his support in a letter published last week by The Baltimore Sun. “With so much at stake, it’s right that the Maryland Public Service Commission and other stakeholders take a hard look at what this merger will mean for consumers. But it’s also clear that Exelon has been a reliable partner, and it has the track record to prove it,” he wrote.
Hearings before the PSC are scheduled to begin Jan. 26. Hearings in New Jersey are set for Jan. 12. Both D.C. and Delaware have scheduled hearings for February.
Exelon withdrew its application for a water-quality permit for its Conowingo Hydroelectric Generating Station after state regulators indicated they would deny the permit.
Exelon said it will spend $3.5 million over the next two years to study the environmental consequences of sediments building up behind the Susquehanna River dam. The Maryland Department of the Environment had said it would deny the permit without more information about the sedimentation and its implications downstream in Chesapeake Bay. The department expects Exelon to reapply within three months.
The Federal Energy Regulatory Commission has already given Exelon a one-year operating license extension.
Dominion’s New Virginia Plant Goes into Operation on Schedule
The 1,329-MW Warren County Power Station, Dominion Virginia Power’s newest electric generating plant, went on line last week.
The $1.1 billion plant was completed on budget and on schedule, the company said last week. Construction began in March 2012. The natural gas-fired combined-cycle plant, just north of Front Royal, Va., has three combustion turbines, three heat-recovery steam generators and a steam turbine.
As a condition of its permits, Dominion agreed to close its coal-fired North Branch Power Station in West Virginia.
Duke Critic Launches TV Attack on Company’s Solar Record
NCWarn, an environmental and consumers’ rights group, has launched a series of satirical TV commercials slamming Duke Energy’s commitment to solar energy.
NCWarn Director Jim Warren said the ads are meant to show viewers that while Duke says it is a solar energy proponent, it really is trying to weaken the state’s solar energy rules to freeze out private solar development.
In response, Duke pointed out that the company plans to spend more than $500 million next year to build solar plants to meet a 2015 requirement that 6% of its retails sales are from renewable sources. The company has contracted to build or buy 278 MW of solar capacity in the coming year, helping push North Carolina to the third leading solar producer in the country. The North Carolina Utilities Commission approved the plan
“These projects will help provide significant amounts of cost-effective renewable energy to benefit our customers, comply with our state obligations and provide meaningful investments in the communities we serve,” said Rob Caldwell, the company’s senior vice president for distributed energy resources. By the end of 2015, Duke expects to produce or procure a total of 748 MW of solar capacity.
PPL’s Susquehanna Nuke Plant Shut Down by Water Leak
A water leak inside the containment structure surrounding the reactor at Susquehanna nuclear station Unit 1 prompted PPL employees to shut down the reactor, company officials said Saturday.
Although the leak was contained and did not pose a risk to the plant or human safety, the company decided to shut down the reactor and perform repairs as part of its winter readiness program. The company said it expected the repairs to be completed quickly.
Life sciences and materials company DSM opened a 6 MW solar facility at its manufacturing plant in Belvidere, N.J.
The solar panels are glazed with the company’s KhepriCoat coating that reduces sunlight reflection, improving energy production by up to 4%. The solar field was developed with GeoPeak and Marina Energy, and at peak production it will supply 30 to 40% of the plant’s energy needs.
Wetlands transmission line installation. (Source: Pepco Holdings Inc.)
Four companies vying for a contract to address stability problems at Artificial Island squared off in a tense PJM Transmission Expansion Advisory Committee meeting Dec. 9 before an unexpected crowd that required organizers to employ an overflow room.
The meeting had the atmosphere of a political debate as representatives from Transource Energy, LS Power and Dominion Resources delivered 30-minute presentations pitching their proposals. The fourth contestant, Public Service Electric & Gas, used its time to attack Dominion’s plan for using what it called untested technology.
PJM planners expect to present a final recommendation at the Jan. 8 TEAC meeting, in time for consideration by the Board of Managers in February, said Steve Herling, vice president for planning.
All of the potential solutions involve new transmission lines connecting Artificial Island, home to the Salem-Hope Creek nuclear complex, to Delaware.
LS Power and Transource are proposing a southern crossing of the Delaware River. Dominion and PSE&G are proposing a northern route with an overhead crossing. Both paths are expected to face permitting challenges, according to Paul McGlynn, general manager of system planning.
LS Power’s proposal includes both overhead and submarine options for the river crossing, each of which would carry a binding cost cap of $146 million.
“We are the only company that has offered PJM a significant cost cap,” LS Power Vice President Sharon Segner said. “We are taking on risks associated with real-estate costs, environmental mitigation costs, overhead/submarine river crossing costs and routing costs.”
She also touted her project’s proposed timeline of 42 months.
Transource emphasized its 50-50 partnership with Pepco Holdings Inc. and said its submarine proposal will have the easiest time obtaining permitting.
While it has not agreed to a cost cap, the company would forego 50% of any return-on-equity incentives on costs from $203 million to $255.3 million and all such incentives on any costs exceeding $255.3 million.
Ronnie Bailey, manager of transmission planning for Dominion, emphasized among his proposal’s advantages a 36- to 48-month turnaround time. The project’s cost of $164 million to $174 million also carries the least risk of cost overrun, he said.
Dominion’s solution combines thyristor controlled series compensation (TCSC) technology with static VAR compensators (SVCs) to ensure stability.
While a third-party study commissioned by PJM concluded Dominion’s model “proved stable for all critical faults,” according to McGlynn, the technology was widely challenged at the meeting.
PSE&G led the attack. Instead of speaking on their own proposal, PSE&G representatives used their half-hour to deliver a 25-slide presentation bashing Dominion’s plan as untested and unsafe.
PSE&G also cited criticism by its sister company, PSEG Nuclear, the operator of the Salem and Hope Creek plants.
“The use of the second-largest nuclear site in the U.S. as a test bed for a first-of-its-kind transmission design is problematic and presents potentially dire consequences,” PSEG Nuclear Vice President Christopher Schwarz said in written comments. “The potential consequences arising from a failure of the proposed design to provide both stability and SSR (sub-synchronous resonance) protection when called upon are simply unacceptable from a nuclear safety perspective.”
Dominion’s Bailey called such comments “misinformation” based on the performance of conventional capacitors, not the modern devices Dominion would use.
“The bottom line is these things work, and it’s been vetted by PJM,” he said. “TCSC is now an option to mitigate SSR, and it’s nothing to be afraid of.”
For its part, PSE&G has agreed to a cost cap of $221 million for its proposal, which faces siting hurdles in crossing protected wetland and wildlife areas in New Jersey. (See Two of Four Artificial Island Finalists Offer Cost Caps.)
PJM planners had recommended PSE&G’s selection for the project but re-engaged the other three companies after being widely criticized this summer by environmentalists, New Jersey officials and spurned bidders. (See PJM Puts the Brakes on Artificial Island Selection.)
The project is PJM’s first under the Federal Energy Regulatory Commission’s Order 1000, which opens up transmission line projects to non-incumbent companies.
Despite the hype, solar power still accounts for a fraction of U.S. electricity production, according a recent report by the Energy Information Administration.
The December 2014 Short-Term Energy Outlook estimates solar generation will make up only 0.6% of electricity generation in 2015. “While solar growth has historically been concentrated in customer-sited distributed generation installations, utility-scale solar capacity slightly more than doubled in 2013,” the EIA said.
“EIA expects that utility-scale solar capacity will nearly double again between the end of 2013 and the end of 2015, with about two-thirds of this new capacity being built in California.”
NRC Inspectors Find Radiation Monitoring Problems at Entergy’s Palisades Plant
Nuclear Regulatory Commission inspectors cited Entergy’s Palisades nuclear plant in Michigan for using an improper methodology to measure radiation levels that workers received during a refueling outage earlier this year.
An NRC spokesperson said no workers were overexposed, but proper procedures were not followed, constituting a safety violation. An Entergy spokesman said the company tried to use a new monitoring technology, but it was improperly implemented. The violation could result in increased oversight.
Midwest Railroad Coal Delivery Topic of FERC Panel Discussion
The Federal Energy Regulatory Commission will discuss concerns about the coming winter, coal stockpiles and railroad congestion at its meeting on Thursday.
Competition with shale-oil producers for railroad capacity has put pressure on timely deliveries of coal, causing worries that Midwest power plants may have trouble securing adequate coal deliveries this winter.
The meeting will feature a panel discussion with staffers from FERC and the Surface Transportation Board, as well as representatives from Minnesota Power, BNSF Railway and MISO.
The Senate voted 86-12 to confirm Democrats Ron Walter and Virginia Lodge to the Tennessee Valley Authority board. They will serve five-year terms on the nine-member board that oversees the TVA.
Walter, a television executive, and Lodge, a business consultant and former commissioner of the Tennessee Department of Human Services, are succeeding Barbara Haskew and Bill Sansom.
Walter and Lodge pledged to recuse themselves from any decisions involving TVA’s unfinished Bellefone Nuclear Plant. Both appointees had previous contacts with Chattanooga businessman Franklin Haney, who is advocating a private financing plan to complete the two-reactor plant in Alabama.
Department of Energy Issues $12.5B Nuclear Loan Program
The Department of Energy is offering $12.5 billion in loan guarantees for advanced nuclear energy projects that would reduce, avoid or sequester greenhouse gas emissions.
“This solicitation will help the U.S. build the next generation of safe and secure nuclear energy projects by providing the critical financing needed for innovations that have not been widely deployed at commercial scale in this country,” Energy Secretary Ernest Moniz said.
The Advanced Nuclear Energy Projects solicitation is one of four loan programs totaling $40 billion aimed at boosting low-carbon technologies. The other programs include $8 billion for fossil energy projects, $4 billion for renewable- and energy-efficiency projects and $16 billion for vehicle manufacturing.
The Federal Energy Regulatory Commission ranked fifth out of 25 mid-sized federal agencies in employee satisfaction and commitment, according to a survey of government agencies.
The nonprofit Partnership for Public Service gave FERC a 73.3 out of 100 in employee satisfaction and commitment, and a 77.5 in work-life balance. Only the Federal Deposit Insurance Corp., Government Accountability Office, Smithsonian Institution and Federal Trade Commission scored higher in the “2014 Best Places to Work in the Federal Government” survey.
FERC’s Office of General Counsel won the No. 1 spot among agency divisions with an 88.8.
PJM Market Monitor Joe Bowring said last week that the RTO should exclude supply-side stakeholders from participating in the drafting of cost development guidelines that determine generator compensation.
Bowring, speaking at PJM’s annual Market Monitoring Unit Advisory Committee meeting Friday, said he is contemplating a filing with the Federal Energy Regulatory Commission in 2015 to push for the change.
“It’s an accretion of things that have built up,” he said. “We are pretty unhappy [with the current rules]. We’re saying generators shouldn’t have an effective veto right” regarding changes.
The cost development guidelines, which govern compensation for generators receiving cost-based rates, are contained in PJM Manual 15.
Bowring acknowledged that the manual is subject to sector-weighted voting at the Markets and Reliability Committee and must also win approval from PJM’s Board of Managers — the only manual on which the board votes.
But he said the primary motion brought before the MRC is the result of a skewed process at the Cost Development Subcommittee, at which there is no sector-weighting and where generator representatives can overwhelm other stakeholder factions.
The MRC considers as a “primary” motion the proposed solution that receives the highest vote total at lower committees. Proposals that receive at least 50% support at the lower committee may be offered as secondary proposals if the primary proposal fails to win a two-thirds sector-weighted vote.
Bowring said he would attempt to win support for the change through the stakeholder process but wasn’t optimistic about the chances of success. He said a FERC filing would not come before the middle of 2015 because of other pressing matters, including a FERC filing on proposed changes to the calculation of lost opportunity costs, expected in January. (See p. 21 of the State of the Market report for the third quarter of 2014.)
Bowring’s proposal found no immediate support among stakeholders in attendance. “I can’t see changing the voting approaches without disenfranchising somebody somewhere,” said Dan Griffiths, executive director of the Consumer Advocates of PJM States.
John Horstmann of Dayton Power and Light noted that the Cost Development Subcommittee hasn’t held a meeting since October 2013. “I’m not sure I see the problem to the extent that you see it,” he said.
Disclosure of Market-Sensitive Information
Earlier in the meeting, Jeffrey Mayes, the Monitor’s general counsel, made a pitch for stakeholder support for protections against disclosure of confidential market-sensitive data through discovery in mergers and litigation.
Mayes said the Monitor had fought for tight restrictions on who could see data in the Exelon-Constellation merger and quashed a subpoena in a challenge to New Jersey’s Long Term Capacity Agreement Pilot program.
“If we hadn’t taken those steps [in the merger] almost everyone’s market information would have been made pretty public,” Bowring said.
Mayes said the Monitor’s position would be enhanced by explicit backing of PJM stakeholders.
“I would have been in a far better position if I could have a set of rules that had been worked out in advance and that members of the industry were behind,” Mayes said.
Mayes said PJM’s current rules “have a lot of process but not a lot of substance.” He said ISO-NE has a better definition than PJM of member confidentiality.
This proposal found a better reception among the members in attendance. “It certainly seems like something worth investigating,” said Dave Pratzon of GT Power Group, which represents generators.
State regulators and public advocates last week filed a new complaint in their nearly two-year effort to force a reduction in the formula transmission rates for Baltimore Gas and Electric and Pepco Holdings Inc. utilities.
Officials in Delaware, Maryland, New Jersey and D.C. said they opened the new docket (EL15-27) to introduce an updated rate analysis that takes into account updated financial market data and the Federal Energy Regulatory Commission’s June order revising the method for calculating base returns on equity. (See FERC Splits over ROE.)
The complainants asked that the case be consolidated with their 2013 complaint (EL13-48). That case is scheduled to go to hearing next July, after settlement talks reached an impasse last month.
The new complaint seeks to reduce the companies’ base ROE to 8.8%. The companies are currently receiving ROEs of 10.8% on facilities placed in service before Jan. 1, 2006, and 11.3% on facilities added afterward.
PHI affiliates affected are Potomac Electric Power Co. (PEPCO), Delmarva Power & Light and Atlantic City Electric.
Low Oil Prices not Expected to Slow Fracking Next Year
Despite a drop in oil prices brought on in part by increased U.S. production, oil and gas exploration is still expected to begin in southern Illinois, according to industry officials.
“We are going to continue with our evaluation in Illinois even at these prices,” said Mark Sooter, business development manager of Woolsey Operating. The company’s sister corporation, Woolsey Energy, is a leading holder of oil and gas leases in the New Albany Shale formation.
Fracking was approved by the state this year, and permitting is beginning. Pending any legal blocks, the first wells could be drilled by the middle of next year.
ComEd, Ameren Illinois Rate Hikes Gain ICC Approval
The Commerce Commission last week approved overall rate increases of 11% for Commonwealth Edison and 17.4% for Ameren Illinois, increasing annual revenue about $245 million for ComEd and about $137 million for Ameren.
The rates were set using a formula that is based in part on the companies’ investment in infrastructure, such as smart meters and smart grid technology. “The power grid is evolving and it is my belief that these investments will result in positive changes and new innovative energy services for customers,” ICC Chairman Doug Scott said.
The Citizens Utility Board, an advocacy group, said it would appeal the rulings.
State May Look to Hydro for Next Energy Boon After Wind
With the state ranking third in the U.S. in wind energy production, a legislator says it is time to look at increasing hydropower resources.
State Rep. Dan Kelley plans to ask for the state to put aside money to study hydro power. “The state of Iowa has become a national leader in wind energy, and that shows we have the wherewithal and the interest to pursue renewables to a great extent,” Kelley said. “There’s no reason we can’t do the same with hydropower.”
A 2012 U.S. Department of Energy study estimated that the state has 427 MW of untapped hydro power – quadruple its current capacity, but only a tenth of its 5,000 MW of wind capacity. Wind power currently accounts for 27% of the state’s electricity.
Coal Supplies Already Low at Some Midwest Power Plants
A transportation official told lawmakers that rail congestion and cold weather have already limited coal supplies at some Midwest power plants, but a warm up may allow stockpiles to be rebuilt before winter really arrives.
“We are at the whim of Mother Nature at this point,” said Dave Christianson of the Department of Transportation. He told the Legislative Energy Commission that some plants saw their stockpiles drop to 10% of capacity earlier this year, and supplies now average 30 to 40%.
Railroad officials said a sudden increase in coal shipping demands last year was one cause of rail line congestion. But incoming chairman of the House jobs and energy committee, Republican Rep. Pat Garofalo, said trains are too busy hauling oil from the Bakken oilfield to transport coal and crops. Garofalo supports more pipeline construction.
AG: Utilities Should Pass on Savings from Corporate Tax Cut
Attorney General Roy Cooper is appealing a decision of the Utilities Commission that allowed utilities to keep proceeds from corporate state income tax cuts rather than passing them on to customers.
The lower corporate tax rate was approved in 2013 by the General Assembly, which also raised the taxes paid by customers on their utility bills. This fall, the commission reversed an earlier ruling and said it couldn’t lower customer rates to reflect the lower corporate taxes.
“Utility shareholders were allowed to pocket the cost savings associated with the reduced state corporate income taxes while most customer bills increased from the combined effect of the other tax changes,” according to the attorney general’s filing with the state Court of Appeals last week.
Duke Plan to Repair Leaking Pipe at Charlotte Coal Ash Dump Gets OK
State environmental officials approved a Duke Energy plan to empty contaminated wastewater from a coal ash dump at its Marshall Steam Station near Charlotte to fix a leaking drainage pipe.
The leaking pipe was discovered about six months ago after a similar pipe collapsed at the company’s Dan River plant, contaminating 70 miles of river and sparking an investigation into all of Duke’s coal ash lagoons. State Dam Safety Engineer Steve McEvoy said it has received requests for permits to conduct repairs at 18 of the company’s 32 coal ash sites throughout the state.
Wolf Appoints Former PUC, DEP Chief to Planning Post
John Hanger
Governor-elect Tom Wolf named John Hanger, the former Department of Environmental Protection secretary who oversaw the massive growth of the state’s shale-gas industry, as his planning and policy secretary.
Hanger, who ran for governor this year but endorsed Wolf after dropping out, served on the Public Utility Commission from 1993 to 1998 under Gov. Robert Casey and was former Gov. Ed Rendell’s DEP secretary from 2008 to 2011. He will work alongside another former gubernatorial challenger, Katie McGinty, whom Wolf named as his chief of staff last month. McGinty was also Hanger’s predecessor as secretary at DEP.
Permits Issued for Fracking Under Ohio River by State
West Virginia has approved three permits to drill for oil and gas under the Ohio River.
The state, which controls the rights beneath most of the land underlying the river, says the money earned from leasing the acreage and any royalties earned from production will be put in the state parks budget. With horizontal drilling techniques, production companies can access the deep shale formation from well sites on the river banks.
The drilling companies must still obtain state Department of Environmental Protection permits before beginning. Josh Jarrell, deputy security and general counsel of the state Department of Commerce, said the state has adequate protections in place to ensure water quality is not hurt by drilling under a body of water. Drilling beneath bodies of water is a common practice in other states.
The Public Service Commission will hold hearings throughout the state to examine a plan by Xcel Energy and American Transmission Co. to build what would be the most expensive transmission line in state history.
The 345-kV Badger-Coulee line would run about 180 miles from Madison to Lacrosse and cost between $540 million and $580 million, funded by rate increases to Xcel and ATC customers. The line, first proposed in 2010, is designed to bring increased renewable power production, mostly wind energy, into the MISO system.
MISO’s Board of Directors last week approved a $2.5 billion transmission expansion plan funding 369 projects, including a 500-kV line to carry Canadian hydropower to Minnesota Power customers.
The $676 million Great Northern Transmission Line is the single most expensive project in MISO’s 2014 Transmission Expansion Plan, the product of 18 months of work by MISO stakeholders. The line, which will connect the Manitoba border to the Minnesota Iron Range, is set for completion around 2020.
The plan also includes 50 baseline reliability projects totaling $269.5 million, six generator interconnections totaling $38 million and 312 “other” projects totaling $1.5 billion, including those supporting lower-voltage transmission systems.
The plan will allow for the interconnection of 726 MW of new wind generation and import of 883 MW of hydroelectric power from Manitoba, said Jennifer Curran, MISO’s vice president of system planning and seams coordination, in a memo to the board.
Interconnection requests are shifting from predominately wind to a mix of natural gas and wind, as gas-fired generation steps in to replace coal plants forced to retire or switch fuels because of federal environmental rules, MISO said. Natural gas interconnection requests in MISO soared to 9,424 MW this year, from 1,994 MW in 2011.
There also have been about 810 MW of new solar request interconnections in 2014. “This could be the result of recent federal energy legislation and the economic stimulus package, and the lower price of solar photovoltaic modules,” the MISO plan states.
MTEP 14 was the first planning cycle that included full participation of MISO’s south region in economic and reliability planning.
The south region is targeted to receive about $359 million in transmission investments, including two of the largest projects in MTEP 14: a $60 million, 115-kV line by Entergy in Mississippi, and a $56.3 million, 230-kV line in Louisiana.
Since MTEP ‘03 about $19 billion of transmission project investment has been identified, with roughly 40% of it completed. MTEP 14 covers projects expected to be completed by 2023.
If you want to know why many think that demand response hasn’t fulfilled its potential in MISO, talk to Brian Helms.
Helms, the director of energy services at new MISO member Century Aluminum, said that when he attended a MISO workshop he was unable to get an answer about what form of approval would be needed to register his plant as a Load- Modifying Resource. And when he asked his local utility how to sign up, it told him it wasn’t interested.
“The path to providing those resources is kind of tortuous and murky,” Helms recounted at the MISO Advisory Committee’s “hot topic” discussion on demand response last week.
The committee sought stakeholder input on how to make the most of demand response programs, and whether MISO should take any action while waiting for final word on whether last May’s appellate court ruling voiding the Federal Energy Regulatory Commission’s Order 745 will stand.
Unlike PJM, most of MISO’s demand response assets are administered through state programs. While that means less disruption if the D.C. Circuit Court of Appeals ruling in the Electric Power Supply Association v. FERC case stands, stakeholders told the committee the disparate state rules make it more of a challenge for the RTO to maximize such resources. (The D.C. Circuit yesterday granted the U.S. Solicitor General’s request for more time to seek a Supreme Court rehearing of the case.)
Representing end-use customers, DeWayne Todd, energy services manager at Alcoa in Newburgh, Ind., said that MISO has done a good job of integrating available Load-Modifying Resources through legacy interruptible electric service rates.
Demand Response Resources ‘Untapped’
But Demand Response Resources are largely untapped in the energy and ancillary services markets due to retailers’ restrictions on participation and compensation, the End-Use Sector said. They cited the Independent Market Monitor’s State of the Market report, which shows there are just 75 MW of controllable Demand Response Resources — all attributable to Alcoa, which often interrupts production when electric price signals rise. (See chart.)
“I think there’s a huge opportunity, and not just [in] smelting, but other customers and consumers, as well,” Todd said.
The Environmental Sector agreed, saying MISO’s minimum threshold of 5 MW for participation in energy and ancillary services markets is too high. PJM’s threshold, they noted, is 100 kW.
The Environmental Sector recommended MISO employ demand response as a “transmission-like resource” in its planning, saying DR resources could help maintain reliability at lower cost than System Support Resources while longer-term transmission or generation solutions are implemented. “DR can also reduce or eliminate the need for costly transmission upgrades, or be paired with a transmission upgrade or voltage support to help eliminate potential reliability issues,” it said.
Aggregators ‘Frozen Out’
The environmentalists lamented that third-party providers, which play a big role in PJM, are “largely frozen out” of MISO’s markets. Among MISO states, only Illinois permits aggregators of retail customers (ARC) to participate, they said.
The Organization of MISO States said MISO “has done an adequate job of meeting FERC requirements for DR, while balancing stakeholder desires for sometimes conflicting market parameters.”
It urged the RTO to work with market participants to accommodate new demand response technologies and remove barriers to participation. OMS cited methods of directly controlling customer-owned electric water heaters to support grid reliability. Participants “would like to develop programs to offer this DR in MISO’s ancillary services market, however current MISO protocols, relating to metering and zonal boundaries, may be prohibiting participation,” OMS said.
The Transmission-Dependent Utilities Sector said MISO has allowed DR fair access to its markets and said load-serving entities should continue to have the option to operate their DR programs at the retail level, without offering it as a wholesale product.
Reliability Benefits
The Public Consumer Group acknowledged that the state-by-state variation in demand response programs is a challenge for MISO but that the RTO should nonetheless make increasing DR a top priority, saying such resources could aid reliability and reduce rates.
During last winter’s polar vortex, the group said, MISO did not even consider calling on DR resources, unlike PJM. “As a result, capacity margins were unnecessarily tight, and prices, which were ultimately passed on to consumers, were likely higher than necessary,” it said. “In addition to paying higher prices when DR is not called upon in near-emergency circumstances, end-use consumers in MISO are not getting appropriate use of DR resources for which they are paying in their rates. … Because DR is so rarely called upon, customers are not enjoying the full value of these resources.”
IPPs: Demand Response Has No Place on Supply Side
MISO’s independent power producers took a position similar to that of generators in PJM and ISO-NE, citing the EPSA ruling in arguing that demand response has no place in the supply side of wholesale markets. “MISO will need to establish parameters for load-serving entities and state regulators in order to use these assets focusing on their primary function: load modification, also known as load shaving,” they said.
“There’s a lot of uncertainty, but it’s pretty clear if you look at ISO New England and PJM, they’re being very proactive in what they’re doing with DR and moving it back over to where it traditionally was prior to the advent of organized wholesale markets,” Mark Volpe, senior director of regulatory affairs for Dynegy, told the committee.
Advisory Committee Vice Chairman Kevin Murray said that’s problematic.
“You could take an approach as Mark suggested and force all the demand response back on to the load side of things,” he said. “The problem with that, as MISO has observed, [is] it produces a result where it’s not integrated into MISO’s market when it’s dispatched, [and] it has the effect of reducing load, [depressing] prices during a point in time when the system is stressed during an emergency.”
A number of commenters noted that DR programs among the states differ widely, with some going back decades.
Directors Judy Walsh and Michael Curran said MISO might consider offering incentives to replace the many differing utility contracts with a model that would be easier for MISO to manage.
“I wonder if there’s a way to structure a new opportunity for these players where they would opt-in to some other opportunity to participate in the market where in fact [they] get paid for participating,” Walsh said. “Perhaps we could move out of these old contracts.”
