Exelon Generation is joining with two other companies to build what they are calling an emission-free natural gas-fired power plant.
Exelon is partnering on the project with CB&I, an energy infrastructure company in The Woodlands, Texas, and technology commercialization firm 8 Rivers Capital of Durham, N.C., under the name NET Power. The $140 million, 50-MW plant, which will incorporate carbon-capture technology, will be built in an undisclosed location in Texas.
Using an 8 Rivers technology called Allam Cycle, the new plant will be radically different from conventional combined-cycle plants, which use waste heat to make steam that turns a turbine. Much of the steam’s energy potential is lost when it is condensed.
Pure Oxygen
The Allam Cycle uses natural gas as a fuel. But instead of using air as part of the combustion process, it uses pure oxygen, which eliminates emissions such as nitrogen oxides.
The Allam Cycle uses another byproduct of typical combustion, carbon dioxide, as a type of fuel itself. Rather than having to expend energy to capture CO2 as in other carbon-capture processes, the Allam Cycle collects the CO2, pressurizes it into a liquid and uses it to turn a Toshiba-designed CO2 fluid turbine, instead of a steam turbine. When the power plant is done with the CO2, it is pipeline-grade material ready either for sequestration or to be sold off for industrial uses.
“The by-products of combustion in this system are high pressure CO2 and a small amount of water,” NET Power Spokesman Walker Dimmig said.
“This technology is a potential game-changer in reducing carbon emissions from power generation,” Exelon President and CEO Chris Crane said.
The consortium can’t look to other models of this technology. “This is a true, first-of-a-kind demonstration of a brand new technology,” Dimmig said in an interview Friday. “The first commercial facility, which will be 295 MW, is in the planning stages. Following successful demonstration at this small-scale plant, we of course hope to build many, many more of these.”
Dimmig said he anticipates the Texas plant to be commissioned in 2016.
Holy Grail
Carbon capture is the Holy Grail in low-emissions power generation, but previous attempts have been over budget and behind schedule. Perhaps the most well-known is the FutureGen project, a coal-fired plant using integrated gasification combined-cycle technology, combined with carbon capture and storage. After funding battles and significant cost overruns, FutureGen, which was announced in 2003, is still not operational.
Another carbon-capture project is being built by Southern Co. with engineering and construction firm KBR Inc., in Kemper County, Miss. Originally estimated to cost $2.4 billion, latest estimates for the plant are $5.5 billion. Construction began in 2010. It is projected to go operational in May 2015, a year behind schedule.
How will NET Power avoid these pitfalls?
“First, FutureGen and Kemper are full-scale commercial facilities of a much larger size than this 50-MW facility,” Dimmig said. “Second, this plant has been under design for nearly four years, and we believe we have a very strong handle on costs. Finally, while novel, this is a far simpler process that uses far less piping and exotic alloy as compared to those other projects.”
Dimmig wouldn’t say if the plant must be sited near oil and gas wells, the typical sequestration sites used in carbon-capture plans, to be economically viable. Exelon, too, declined comment on where it planned to site similar plants if the NET Power plant turns out to be a success.
While many stakeholders still have misgivings about it, PJM’s Oct. 7 revisions to its Capacity Performance proposal appear to have won over Independent Market Monitor Joe Bowring.
Bowring said last week that PJM’s revisions have addressed his most significant concerns and that he now supports it. “I think what PJM’s doing here is an excellent idea,” he said during a discussion at the Organization of PJM States Inc.’s annual meeting. “My disagreements or differences are now points of detail instead of major points of principle.
“I think it’s important to keep that in context,” he added, prompting laughter, “as I go through criticizing it mercilessly.”
At a meeting with stakeholders Wednesday, PJM Executive Vice President for Markets Andy Ott said PJM plans to “evolve into a single [Capacity Performance] product over time” after a transition of “a few years” with the current Base Capacity product. That addresses one of Bowring’s central concerns — that multiple products could create opportunities for economic withholding.
Ott said PJM staff is still working out the details of a transitional mechanism. “More discussion could occur without having to decide that in the short term,” he said.
Bowring said a transition is “appropriate. These are very significant changes that are being dropped on the market in a very short period of time. But if we create a second product … sometimes it’s very difficult to get rid of them. They create those who make money from them, people who support them in the stakeholder process,” he said.
At the stakeholder meeting, Ott left the door open to reconsidering the plan’s insistence that all new resources be Capacity Performance. Consultant Tom Rutigliano of Achieving Equilibrium and Judith Judson of Customized Energy Solutions said advanced energy storage might not qualify as Capacity Performance but would still be valuable to PJM as Base Capacity.
“If you’re saying they can’t [qualify as Capacity Performance] we’ll have to think about it,” he said.
Next Steps
Stakeholders must inform PJM by Oct. 21 of the coalitions they have formed to address their concerns about the proposal. The coalitions’ briefing papers are due Oct. 28.
The coalitions will make their cases to the Board of Managers, which will decide what changes are ultimately filed with the Federal Energy Regulatory Commission, at an “Enhanced” Liaison Committee meeting in Philadelphia Nov. 4.
Earlier this month, the board received letters of protest from Environment Ohio, which said the proposal is “disruptive and unfairly penalizes renewable energy and energy efficiency,” and two Pennsylvania state representatives, who said it “is likely to significantly increase costs for ratepayers without delivering on its promise for increased reliability for a number of years.”
Reps. C. Adam Harris and Kevin Boyle urged PJM to “find a less disruptive alternative.”
Late yesterday, the D.C. Circuit Court granted a stay until Dec. 16 on its ruling voiding the Federal Energy Regulatory Commission’s Order 745. The stay will give FERC, through U.S. Solicitor General Donald B. Verrilli, Jr. , time to file a petition for certiorari with the Supreme Court. FERC Chairman Cheryl LaFleur said that the decision whether to seek a Supreme Court hearing will be made by Verilli. LaFleur said FERC’s direct authority to initiate legal action ends at the circuit court.
RTO Insider will have updates as the story develops.
DR Providers Push Back on PJM EPSA Response
Marji Philips of Direct Energy (L) and Andy Ott of PJM (R)
CHICAGO — Demand response aggregators told PJM officials last week that the RTO’s proposed response to a court ruling narrowing federal jurisdiction over DR is overly broad and will reduce the resource’s role in the markets.
On Oct. 7, PJM issued a white paper in response to the D.C. Circuit Court of Appeals’ May 23 ruling (Electric Power Supply Association v. Federal Energy Regulatory Commission) that overturned FERC Order 745. Although the order addressed FERC’s authority over DR in the energy markets, FirstEnergy responded to the court ruling by filing a complaint seeking to have DR excluded from the May 2014 capacity auction.
To avoid legal vulnerabilities, PJM proposed eliminating DR as a capacity supply resource and instead having load-serving entities offer DR and energy efficiency to reduce their capacity obligations. (See Awaiting FERC Action, PJM Floats ‘Trial Balloon’ on DR Post-EPSA.)
Boston: Demand Response’s Role Secure
“We believe in our heart that DR has a role in our future,” PJM CEO Terry Boston told the Organization of PJM States Inc. (OPSI) annual meeting last week.
In a panel discussion at the meeting, Katie Guerry, vice president of regulatory affairs for EnerNOC, contended the EPSA ruling does not require any changes to the capacity market. “Capacity is a uniquely wholesale product, unlike energy,” she said, adding that FERC has ruled that capacity is not just and reasonable without DR. If DR is removed from capacity, she said, “every ratepayer’s bill will go up, whether they participate in demand response or not.”
Marji Philips, director of RTO and federal services for Direct Energy, said eliminating DR that has already cleared in capacity auctions would be “a travesty to customers. The demand response is there. It exists. It’s been called on. And by ‘poofing’ it [making it disappear] and saying we can’t match it up so therefore we don’t have the capacity when you do have it, seems to be a very poor way of doing this.”
Stu Bresler, PJM vice president of market operations, said PJM’s proposal was intended to eliminate the uncertainty of a future court ruling that might force the RTO to rerun its auctions. “The last thing PJM wants to do is to ‘poof’ away a reliable asset we’ve already procured,” Bresler said.
At a stakeholder meeting Wednesday, Bresler was unable to answer a question from Mike McMahon of the Illinois Citizens Utility Board about how much of PJM’s demand response could qualify under the RTO’s proposed Capacity Performance product. (See related story, Revised Capacity Performance Plan Wins Bowring’s Support.) Bresler predicted a “significant quantity of DR” would qualify but added, “I don’t have a good number for you.”
From Supply to Demand Side
The PJM proposal would change DR from a supply-side resource to “putting it on the demand side of the equation,” where it can shift the demand curve to the left, Bresler explained. “If the price goes above [the level bid by LSEs] their obligation is reduced.”
While praising PJM for making a proposal, Guerry said its proposal may quash innovation and result in “less choice, higher prices and less operational flexibility.”
More than three-quarters of DR comes via curtailment service providers, such as EnerNOC. Replacing CSPs with LSEs and bundling DR with supply contracts will result in a loss of transparency and customer choice, Guerry said. “The reality is [LSEs] have a business model. More DR lowers the value of their hedges,” she said.
West Virginia Consumer Advocate Jackie Roberts also questioned the feasibility of PJM’s proposed reliance on LSEs.
“If LSEs wanted to be in that market they’d be in that market. They’re not,” she said. [States are] “not capable of that behind-the-meter demand response. That’s why CSPs have that role.”
Not necessarily, according to Philips, who said Direct Energy is partnering with smart thermostat maker Nest Labs to provide DR to residential customers in Texas. “There are LSEs that do want to play in the market,” she said.
Technology Will Prevail
Former Ohio Public Service Commissioner Paul Centolella said technology can help DR overcome the obstacles posed by EPSA. “The technology that is available today is sufficiently speedy, sufficiently granular, that actually you can do much more than what we’ve seen from demand response resources to date.”
Centonella said thermostats such as Nest — which he said is increasing its market penetration faster than the first and second generations of the iPod — can enable “automated customer choice.”
Google purchased Nest for $3.2 billion in February. “Apple has its own strategy. New players are coming into this market from Lowe’s and Best Buy. This will probably really significantly change power markets,” he said.
“Just like Kayak can help you choose the least expensive airfare or Pandora can match your musical preferences, these devices can select the least expensive time in which to use power and they can match a customer’s preferences for savings and comfort.”
CHICAGO – State officials and generation owners promised last week to challenge the assumptions the Environmental Protection Agency used in its proposed carbon emission rule, saying the agency’s cost calculations are too low and its projections for energy efficiency and generator performance too high.
The EPA’s proposed rule was the subject of two panel discussions at last week’s annual meeting of the Organization of PJM States Inc. (OPSI). Members debated whether the EPA has authority to impose emission restrictions “beyond the fence line” of generating plants, discussed the role of PJM and other RTOs in leading a regional compliance effort, and agreed on the need for a reliability “safety valve.”
West Virginia Consumer Advocate Jackie Roberts said the EPA’s estimate that the regulations will increase rates by only one-half cent per kWh are not credible. “I’m having trouble accepting that,” she said. “The costs of the program are going to be enormous.” Roberts said the costs will be regressive, falling particularly hard on the poorest in West Virginia, itself the eighth poorest state in the U.S.
Ohio Public Utility Commissioner Asim Haque said his state’s comments on the rule will include ProMod analyses that show the regulations will cost its consumers billions. “We’re going to submit what we think will be a very strong set of comments that will describe our concerns about the Clean Power Plan. We will not speculate, pontificate or spew rhetoric. We are going to provide true data that support conclusions that we can assert that will effectively work against the [EPA’s] math.”
Kentucky Public Service Commissioner James Gardner said he feared his state might be forced to shutter coal generators on which it has spent $4.5 billion in retrofits to comply with the EPA’s mercury and cross-state air pollution rules.
But Maryland Public Service Commissioner Kelly Speakes-Backman said Maryland and the other eight states in the Regional Greenhouse Gas Initiative (RGGI) cap-and-trade system have seen less than a one-half percent increase in residential, commercial and industrial ratepayers’ bills while reducing carbon emissions 40% and achieving economic growth of 7% between 2005 and 2012.
“We are living proof that a mechanism that’s based on market dynamics can work and it can work to the benefit of our ratepayers and our environment at the same time. Those are not two mutually exclusive issues,” she said.
“If you’re concerned about electricity prices — which I hear a lot of people are — I would encourage you to go out and lock in for the next 15 or 25 years the record-low wind prices so you will know exactly what your electricity prices will be under the Clean Power Plan,” said Tom Vinson, vice president of federal regulatory affairs for the American Wind Energy Association.
Heat Rate, Capacity Factor & Energy Efficiency
John Coleman, vice chairman of the Pennsylvania Public Utility Commission, complained that the EPA did not give his state credit for being an early adopter of renewable portfolio standards and failed to acknowledge the economic impact of shutting down coal-fired generation. “A 32% reduction for Pennsylvania is very significant. In fact it’s probably to the point of being unachievable,” he said.
John McManus, vice president of environmental services for American Electric Power, said the industry can achieve only a 1-2% improvement in heat rates, far below the 6% the EPA assumes. “If you’re giving away 4% of your fuel price because you’re just not paying any attention, that’s not a very smart way to operate, so we think they’re very aggressive there.”
He also challenged the EPA’s assumption that gas generators can achieve 70% capacity factors. While some of AEP’s combined-cycle plants run as high as 70%, to “run all of them year after year at 70% — that’s another question,” he said.
Darren MacDonald, director of energy for Gerdau Long Steel North America, said the rules threaten the viability of his company, which transforms scrap into steel. MacDonald said the company has had to squeeze out energy waste to remain competitive globally. “We’ve been looking for high-hanging fruit for years,” said McDonald.
EPA Authority ‘Outside the Fence’
McDonald said the EPA has no authority to regulate emissions “outside the fence” of electric generators. Virginia State Commerce Commissioner Mark Christie agreed: “I haven’t heard anyone say EPA can regulate outside the fence,” he said, asking: can the EPA force states to increase their RPS targets?
Speakes-Backman said the issue is a “false premise” for states that choose a mass-based compliance.
She noted that RGGI is limited to fossil fuel generators of 25 MW and above. “We are not going outside the fence,” she said. “But if we have energy-efficiency improvements [and] renewable energy that reduces the amount of generation from those affected units, then we’re complying.”
Start Planning for Wind
Vinson said PJM and other RTOs need to begin planning transmission for new wind generation to meet the EPA targets, saying “We know some version of carbon regulation will stand” after the anticipated court challenges, he said. “In our view, 111(d) is clearly a public policy requirement [under FERC Order 1000] that needs to be planned for,” Vinson said.
Vince Hellwig, senior policy advisor at the Michigan Department of Environmental Quality, agreed that officials need to begin planning based on the preliminary rule.
But Hellwig said that the EPA’s proposal won’t give states credit for energy efficiency until 2020. With Michigan’s RPS due to sunset in 2015, Hellwig said some have asked the legislature “why shouldn’t we wait [to renew it] until we get credit for it?”
RTOs’ Role
Hellwig said his state’s compliance is complicated because it is split between PJM and MISO. “How are we going to deal with being in two different ISOs? We don’t know yet,” he said.
Ohio’s Haque called on PJM to be proactive in recommending a path forward for its member states. “PJM has to tell states how to best manage and craft plans based on the reality of the marketplace in which we live,” he said.
“There’s no one better suited than a regional transmission organization to [determine] how that would work,” concurred Speakes-Backman.
Craig Glazer, vice president of federal government policy for PJM, said the RTO is working with other members of the ISO/RTO Council (IRC) to draft a consensus response to the rule, similar to the one that helped persuade the EPA to add a reliability “safety valve” to its Mercury and Air Toxics Standard (MATS).
PJM CEO Terry Boston urged state officials to include a call for a safety valve in their comments on the carbon rule. “We have gotten nowhere with EPA” on the issue, Boston said.
AEP’s McManus noted the emission targets don’t change after the final rule is issued next June. “That doesn’t make sense to us. There has to be an opportunity for a mid-course correction” if, for example, a state loses a nuclear plant to an extended outage.
Environmental Dispatch
State officials sparred over whether the EPA rule will require PJM to replace its security constrained economic dispatch (SCED) with “environmental dispatch.”
Ohio’s Haque said the rule is “effectively masked environmental dispatch.”
Speakes-Backman disagreed. “It wouldn’t work. That’s not what’s being proposed in the guidelines,” she said.
Glazer said PJM could use run-time limits on individual generators as a “back door” way to implement emissions rules. But he said “true environmental dispatch” – stacking units by emissions rate irrespective of cost – “is really something of a nightmare” that would threaten cost discipline and disrupt investment signals. “You’d have the reliability and environmental dispatch sort of at war with each other.”
Former Ohio Public Utility Commissioner Paul Centolella suggested a market-based solution, noting that a cap-and-trade program was able to reduce SO2 emissions for a much lower cost than most had projected.
Michigan Public Service Commissioner Greg White said a market-based solution would be the cheapest way to achieve compliance. But he said such a response would require agreements between states and action by the Michigan legislature.
“How we get there, I have no idea,” he said. “I’m not the decision maker. Not even close to the decision maker.
A Nuclear Regulatory Commission staff report says that the Yucca Mountain nuclear waste repository in Nevada would, “with reasonable expectation,” meet safety requirements.
The 781-page report was ordered when the license for the facility was still under consideration, back in 2008. Since then, the Obama Administration halted work on the project, about 100 miles northwest of Las Vegas.
The National Association of Regulatory Utility Commissioners welcomed the report and urged the administration and Congress to support the continued review of the facility’s license application. NARUC noted that consumers of nuclear energy have contributed billions of dollars over the past 30 years to fund a repository. “Our government owes it to them to finish the job.”
But opponents said the report did not fully consider all the probabilities that could affect safety. “It’s a pretty meek endorsement,” said Robert Halstead, director of the Nevada Agency for Nuclear Projects.
Duke Files for FERC Approval of NCEMPA Asset Purchase
Duke Energy Progress has asked the Federal Energy Regulatory Commission to approve its $1.2 billion buyout of the North Carolina Eastern Municipal Power Agency’s shares of several Duke power plants.
NCEMPA is selling its stakes in four Duke Energy Progress power plants — about 700 MW at two coal-fired plants and three nuclear units. If the deal is approved, Duke will be the sole owners of the Roxboro Unit 4 and Mayo Unit 1 coal plants, and the Brunswick Units 1 and 2 and Harris Unit 1 nuclear stations. All of the plants are in North Carolina.
Duke also entered into a 30-year power-purchase agreement to supply wholesale power to the 32 municipalities represented by NCEMPA. The terms of that agreement were not released.
Duke will also need regulatory approval from North Carolina, South Carolina and the Nuclear Regulatory Commission.
Lockheed Martin Claims Breakthrough in Fusion Power
The magnetic coils inside the compact fusion (CF) experiment are critical to plasma containment, as pictured in this undated handout photo.
Defense contracting giant Lockheed Martin made big waves last week when it announced it had made a technological breakthrough in creating a power source based on nuclear fusion. It said the first reactors — small enough to fit in the back of a truck — could be ready in a decade.
The Lockheed research team, headed by Tom McGuire, has been working on the project at the company’s Skunk Works, its top secret research facility in California. McGuire told Reuters that its designed 100-MW reactor would be about 10 times smaller than current reactors.
The company said it planned to build and test a fusion reactor in the next year, and then construct a prototype within five years. The method, long sought after by researchers, attempts to capture the energy released during nuclear fusion, rather than nuclear fission. Nuclear fusion occurs when atoms combine into more stable forms and is inherently safer. Fusion reactors would use a deuterium-tritium fuel and not produce any radioactive waste.
EPA Fines DOE for Missing Hanford Cleanup Deadlines
The Environmental Protection Agency is fining the Department of Energy up to $10,000 for every week it fails to start removing radioactive sludge at the Hanford Nuclear Reservation on the Columbia River in Washington state.
The DOE had agreed to start the storage basin clean-up by Sept. 30 at the nation’s most contaminated nuclear site, where plutonium was produced. But it missed the deadline, blaming federal budgeting issues. The EPA said it will start the fine at $5,000 for the first missed week before fining the department $10,000 for each additional week of delay.
The DOE had requested a deadline extension but was denied by the EPA.
Last 44M Acres in Gulf Opened to Energy Exploration
The Bureau of Ocean Energy Management is opening the last unleased areas in the central Gulf of Mexico to oil and gas exploration, it announced last week.
The lease sale, to take place in New Orleans in March, will mark the seventh such sale under the Obama Administration’s five-year Outer Continental Shelf Oil and Gas Leasing Program. The first six sales offered more than 60 million acres and produced $2.4 billion in federal revenue.
The blocks to be leased off Louisiana, Mississippi and Alabama run from 3 to 230 miles offshore, in water from 9 feet to 11,000 feet deep. The bureau estimates the 44 million acres could produce 460 million to 894 million barrels of oil and 1.9 trillion to 3.9 trillion cubic feet of natural gas.
Jeff Baran is sworn in as a NRC commissioner by Chairman Allison M. Macfarlane (right) as his wife Michelle Yau looks on. (Source: NRC)
Jeff Baran was sworn in as a member of the Nuclear Regulatory Commission and will serve until June 30, 2015, the remainder of William Magwood’s term. Magwood accepted a position with the Paris-based Nuclear Energy Agency.
NRC Chairman Allison M. Macfarlane administered the oath of office. “We have substantial work ahead of us and I am confident that Jeff will make a valuable contribution to our mission,” she said. Baran was staff director of Energy and Environment for the U.S. House Committee on Energy and Commerce, and had NRC oversight duties in that position.
Cove Point Opponents File Rehearing Request with FERC
A group of environmental and customer advocates filed a motion seeking a rehearing of the Federal Energy Regulatory Commission’s approval of the Cove Point LNG export terminal, saying the agency’s OK was based on an inadequate environmental review.
Earthjustice, representing groups such as the Sierra Club, Lower Susquehanna Riverkeeper and the Chesapeake Climate Action Network among others, also filed a motion to stay, hoping to stop initial construction at the site on the Chesapeake Bay in southern Maryland.
“In neglecting to prepare a thorough review of the environmental impacts of Dominion’s controversial project, FERC is prioritizing the desires of a powerful company over the health and safety of the people of Calvert County, Marylanders and communities throughout the Marcellus Shale region,” Earthjustice Associate Attorney Jocelyn D’Ambrosio said.
The Tennessee Valley Authority has completed the nation’s first nuclear backup facility built in response to the 2011 disaster at Japan’s Fukushima Daiichi facility.
The fortified facility, serving the TVA’s Watts Bar Nuclear Plant in Spring City, Tenn., is an $80 million bunker protecting pumps and generators. It was built on bedrock with 18-inch concrete walls and designed to withstand earthquakes, fires and even a missile attack.
The TVA is the first U.S. utility to finish a backup center. Many other nuclear sites in the U.S. are either planning such facilities or already building them, in response to orders from federal regulators.
DOE Funds Combined Heat, Power Project at Aberdeen
The Department of Energy is helping to fund a 7.9-MW combined heat and power (CHP) project to replace the aging steam plant at the Army’s Aberdeen Proving Ground in Maryland. CHP, also known as cogeneration, uses a single station to provide both electricity and heat, usually in the form of steam.
The DOE will replace the facility’s steam plant, which is being decommissioned in 2016, with a CHP plant that will provide 86% of the site’s steam needs and 50% of its electricity. The project will also develop standard protocols — including design, air permitting and electrical interconnection — that can be replicated at other defense facilities.
Other projects included in the DOE’s $2 million in funding are a 13.7-MW plant at NASA’s Johnson Space Center in Houston and the National Science Foundation’s Arctic Program at Thule Air Force Base in Thule, Greenland.
Low-Carbon Energy System Could Save Trillions, Study Says
Transitioning to a low-carbon energy system could free up trillions of dollars of investment capital, spurring economic growth, according to a report by the Climate Policy Initiative.
The report estimates the worldwide cost of building and maintaining low-carbon energy systems and transportation systems. A second section of the report calculates the economic costs of decommissioning existing fossil fuel assets. It concludes the transition could free up $1.8 trillion for investment between 2015 and 2035.
It said concentrating the phase-out on coal assets could provide the largest emissions cuts with the least financial loss.
“Our analysis reveals that with the right policy choices, over the next 20 years governments can achieve the emissions reductions necessary for a safer, more stable climate and free up trillions for investment in other parts of the economy,” CPI senior director David Nelson said. “This is even before taking into account the environmental and health benefits of reducing emissions.”
Xcel Energy says changing environmental regulations are forcing it to shut down the 232-MW coal-fired units at Black Dog power plant in Burnsville, Minn.
Xcel told MISO last week that the Black Dog plant has been a cost-effective, reliable energy resource for more than 60 years. “But there is a cost associated with the modifications needed to operate these coal units under new federal air emission rules. Retiring the units will benefit our customers by not only avoiding those costs but also reducing emissions.”
A 300-MW natural gas-fired plant at the site will remain in operation. The two coal units will go dark in April.
Dynegy issued $5.1 billion in debt just before bond yields increased to their highest levels in a year, lifting the prices of the underlying notes.
“They priced the deal in the middle of the carnage and prices popped right after the sale,” Andy DeVries, a CreditSights analyst said the day of the offering.
September saw a sell-off of junk-rated bonds – investors pulled $2.3 billion from funds that buy high-yield bonds in the week ending Oct. 1, according to Lipper data. Dynegy offered its bonds in three tranches, or sections: five-, eight- and 10-year notes.
FirstEnergy says a recent report that contends the company is struggling to remain viable is “misleading and biased.”
The Institute for Energy Economics and Financial Analysis’s report said the company is too dependent upon aging coal generation and is relying upon ratepayer subsidies to “reverse a deepening spiral of debt service and revenue declines.”
But FirstEnergy spokesman Doug Colafella said last week that the company “has taken significant actions —particularly in the past 12 months — to improve our financial position, lower our cost structure and position the company for more stable and predictable growth through our regulated holdings, and overcome the lingering effects of the recession as well as challenging capacity and energy markets.”
“We believe the strategies we have put in place, together with our commitment to operational excellence and financial discipline, will provide long-term value and predictable, sustainable growth to our investors,” Colafella said.
The chief planning official for the grid operator took issue with an environmental group’s claim that continued operation of a generating plant in New Jersey would be a threat to the system.
At issue is the planned switch from coal to natural gas for the B.L. England plant in South Jersey. New Jersey Sierra Club Director Jeff Tittel, citing a PJM report, told area reporters that continued operation of the plant would be a threat to system reliability.
Just the opposite, PJM’s Steven R. Herling, vice president of planning, told Tittel in a letter.
“Recent media statements attributed to you about reliability and cost impacts associated with the B.L. England generating units remaining in service are based on a misunderstanding of PJM Interconnection’s planning process,” Herling wrote. “Simply put, the continued operation of existing generating units at the B.L. England site, absent the addition of significant amounts of new generation, is not projected to result in reliability problems.
“Our transmission-planning process is very complex, dynamic, and — as a consequence — can be misunderstood,” Herling continued. “I would have been very happy to explain the process and underlying facts to help you avoid confusion and would be willing to clarify PJM’s study results at any time.”
Tittel stands by his group’s claims and said PJM was changing its story at the behest of utilities. “They’re trying to spin it any way they can,” he said.
Dominion’s Surry Plant Shuts Down Due to Malfunctioning Sensor
Dominion Resources’ Surry Unit 2 tripped and shut down unexpectedly last week after a sensor mistakenly detected a problem in the reactor protection system, the company announced. The reactor, in operation since 1973, went offline at about 8 a.m. Oct. 13.
“It did just what it was supposed to do,” Dominion spokeswoman Bonita Harris said. “Nuclear plants are designed to shut down automatically when that happens.”
The plant returned to service two days later. The plant last had an unscheduled shutdown in April 2011 after it was hit by a tornado.
Operators of Southern Co.’s Joseph M. Farley Nuclear Plant in Alabama shut down Unit 2 after a lightning strike on a transmission line Oct. 14. The plant was already in the process of going offline for a refueling outage.
Each of the two Farley units requires refueling every 18 months, a process that takes about a month. About 900 Southern employees and 800 contractors will be involved in the effort. Farley Unit 1 remains in service, the company said.
Top 25 US Companies Continue to Increase Solar Installation
(Source: NRG Energy)
The top 25 companies in the U.S. for embracing solar power installed 28% more capacity last year as equipment and installation prices continued to drop, according to the Solar Energy Industries Association.
Since 2012, the 25 companies — including Target, General Motors, Kohl’s and Walgreens — have doubled the amount of photovoltaic capacity installed on their facilities, from 279 MW in 2012 to 569 MW as of August, according to the trade group’s annual report.
SEIA spokesman Ken Johnson said the 30% Solar Investment Tax Credit helped maintain an impetus for the industry’s growth.
MISO industrial customers will get a full hearing on their bid to reduce transmission rates by $327 million a year.
The Federal Energy Regulatory Commission Thursday ordered an evidentiary hearing on the industrials’ complaint that the 24 MISO transmission owners’ base return on equity (ROE) — 12.38% except for ATC, which has a base ROE of 12.2% — is unjust and unreasonable.
The complaint “raises issues of material fact that cannot be resolved based upon the record before us and that are more appropriately addressed in the hearing and settlement judge procedures,” the commission ruled (EL14-12).
The commission rejected an attempt by the transmission owners — including Ameren, Duke Energy and Entergy — to dismiss the complaint on procedural grounds.
FERC opened the door to fights over the maximum allowable ROE in June, when it changed the way it sets return on equity rates for electric utilities that’s now more akin to the process it uses for natural gas and oil pipelines. Ruling in a case involving New England transmission owners, FERC tentatively set the “zone of reasonableness” at 7.03-11.74%. (See related story, New England TOs to Pay Refunds in ROE Case.)
MISO’s industrial customers say the base ROE for MISO TOs should not exceed 9.15%, citing “significantly changed economic circumstances since the base ROEs were first established.”
The commission rejected the industrials’ challenge to the use of capital structures that include more than 50% common equity.
“Complainants have not demonstrated that MISO TOs, individually or collectively, do not meet the requirement of the commission[’s] three-part test, failure of which would call into question the justness and reasonableness of using their actual capital structures for ratemaking purposes.”
The plaintiffs are six groups of industrial customers, including Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Minnesota Large Industrial Group and Wisconsin Industrial Energy Group.
The Environmental Protection Agency’s proposed regulations on carbon emissions would increase electric bills and harm reliability, Virginia State Corporation Commission staff members said in comments filed last week.
SCC staff said EPA’s “arbitrary, capricious, unsupported and unlawful” plan could cost Dominion Virginia Power customers alone between $5.5 billion and $6 billion. “Contrary to [the EPA’s] claim that ‘rates will go up, but bills will go down,’ experience and costs in Virginia make it extremely unlikely that either electric rates or bills in Virginia will go down,” staff said.
The EPA’s proposed regulations, announced in June, call for a 30% reduction in carbon emissions from the country’s existing power plants’ 2005 levels by 2030, with individual targets for each state. (See Carbon Rule Falls Unevenly on PJM States.) Virginia would be required to reduce its generating plants’ emissions to 884 lbs./MWh by 2020 and to 810 lbs./MWh by 2030.
Stranded Investments
The EPA’s modeling predicts that Virginia utilities will have to retire 2,851 MW of fossil-fuel generation and build 351 MW of wind power before 2020, “a timeframe that compromises reliability,” staff said.
The retirements threaten “several billions of dollars of recent investments in existing coal-fired facilities in Virginia and West Virginia that Virginia ratepayers have only begun to pay off. Much of this investment has been constructed to comply with EPA consent decrees on which the ink is hardly dry,” staff wrote.
Staff also claims the regulation would impose more stringent emission requirements on existing generators than the EPA is requiring in a separate standard for new generation.
While existing plants in Virginia will eventually be limited to 810 lbs./MWh, new coal plants, built with the best available carbon-capture technology, are limited to 1,000-1,050 (depending on the size), while new natural gas plants are limited to 1,100.
“It would be hard to imagine the EPA advancing such a proposal in areas that are more familiar to everyday life,” SCC staff said. “Would it be rational to require the current owners of automobiles or lawnmowers throughout Virginia, for example, to meet an emission standard that is 26% more stringent than required for the production of new cars or lawnmowers that must use the best available technology?
“Turning regulation on its head in this way — requiring older, but still useful equipment to meet a standard that the EPA admits cannot be achieved even by entirely new equipment — is a recipe for stranding prior investments and requiring significant additional investment.”
Reliability Impact
SCC staff said that they analyzed Dominion’s 2013 integrated resource plan as a reference to estimate the cost of complying with the EPA’s rule. One of two scenarios in the IRP, the Fuel Diversity Plan, calls for the addition of a third unit at the utility’s North Anna nuclear plant. (See SCC: Dominion IRP Lacks Analysis of Nuclear Plans.)
This plan would allow the state to meet its 2030 goal, the SCC staff said, but they altered it to include 69 MW of wind generation and more coal plant retirements than originally called for to meet the interim 2020 goal.
“These retirements are of grave concern because the power plants involved are used today to ensure reliable service to Virginia customers, have years of useful life remaining and cannot be replaced overnight or without regard for impacts on the electric system,” staff said.
Staff said the regulations set “generic and unsupported expectations of levels” of renewable generation and energy efficiency that “are extremely ambitious, almost certainly unachievable and uneconomic under traditional standards.”
Enviros: SCC Staff ‘Playing Politics’
Several environmental groups, however, criticized SCC staff’s assertions as inaccurate.
“The SCC staff analysis is just plain wrong,” said Glen Besa, director of the Sierra Club’s Virginia Chapter. “They’re playing politics with climate change science and they have no business doing that, and they’re bringing discredit on the commission.”
“The SCC staff crossed the line in their hastily submitted comments to EPA and I think they’ll ultimately regret that mistake,” said Dawone Robinson, the Chesapeake Climate Action Network’s Virginia policy director. “I think they misread the rule.”
Specifically, Robinson questioned the use of Dominion’s Fuel Diversity Plan as a way to comply with the regulations.
“SCC staff seems to suggest that in order to comply with the Clean Power Plan, Virginia needs to invest in a third nuclear reactor at North Anna, and that simply isn’t the case,” Robinson said. “Additionally, many of the coal plant retirements and natural gas conversions that the SCC staff suggests will hamper the state … were proposed by the utility before the Clean Power Plan was even released.”
Robinson’s comments echo those made by Cale Jaffe, director of the Southern Environmental Law Center’s Virginia office, to The Richmond Times-Dispatch.
“It appears the staff has misread the rule,” Jaffe said. “Analyses that we have reviewed show that Virginia is already 80% of the way to meeting Virginia’s carbon pollution target under the Clean Power Plan.
“Almost all of those reductions are coming from coal plant retirements and natural gas conversions that the utilities put in place long before the Clean Power Plan was even released.”
The EPA, which will be accepting comments on the proposed rule through Dec. 1, will issue the final rule in June 2015.
Northern Indiana Public Service Co. has reached an agreement with environmentalists and consumer advocates on a new renewables tariff that will boost payments to small wind farms while cutting prices for solar power.
The pact on NIPSCO’s revised renewable feed-in tariff (FIT), filed Oct. 9 (Case #44393), awaits final approval from the Indiana Utility Regulatory Commission.
Wind power generators of up to 100 kW would receive $0.25/kWh, up from $0.17.
“The purchase price for small wind in [the original FIT] was too low and as a result, the available capacity was not used,” said Kerwin Olson, executive director of Indianapolis-based Citizens Action Coalition. “Expanding small wind is important, so increasing that price will hopefully drive investment in small wind in Indiana.”
The settlement decreases payment for solar power to $0.17/kWh from $0.30/kWh.
Olson said the decrease reflects the falling costs of solar panels while still providing the price support needed to continue solar’s expansion in NIPSCO’s territory. “Solar is not at grid parity yet in Indiana, so it needs a ‘leg up,’” he said.
Residential customers would pay about $1 per month for renewables under the revised tariff, an increase of about $0.25. “We feel that’s reasonable,” Olson said.
Not everyone got what they wanted. The CAC and the Hoosier chapter of the Sierra Club argued that the definition of “qualifying renewable energy power production facilities” under the FIT should exclude facilities fueled by organic waste biomass derived from forest thinning.
The groups also sought exclusion of some types of waste-to-energy facilities, over air and water pollution concerns.
The FIT program is designed to incent customers who generate green electricity from solar, wind, biomass or new hydroelectric facilities. Facilities between 5 kW and 5 MW are eligible. Total capacity available under the FIT is capped at 30 MW.
Among those generally pleased with the settlement is Bio Town Ag, which operates the world’s largest on-farm anaerobic digester generating facilities with NIPSCO, according to Bio Town president Brian S. Furrer. Bio Town, in Reynolds, Ind., has sought multiple purchasers of electricity generated by methane from animal waste, including NIPSCO and other suppliers. The digester generation facility can produce 5 MW.
Also party to the FIT settlement with NIPSCO was the Indiana Distributed Energy Alliance and the Indiana Office of Utility Consumer Counselor.
NIPSCO officials were not immediately available for comment.
A new constructability review of proposed Artificial Island solutions revealed no significant differences in the permitting challenges between the northern and southern Delaware River crossings, PJM told the Transmission Expansion Advisory Committee Thursday.
A PJM consultant compared the permitting challenges between a proposed line crossing the southern part of the Delaware River to a line that runs from the island to Red Lion, Del. “Both will have significant permitting challenges,” said Paul McGlynn, general manager of system planning. “Neither one will be easy.”
McGlynn noted that although two of the four finalists bidding for the job has offered to cap their costs, none has offered a firm “fixed” cost. “They all have exclusions in what’s included and not included” under the cap, McGlynn said.
PJM is continuing its review of the proposals.
Planners Studying EPA Carbon Rule, Ill. Nuke Retirements
PJM staff is analyzing the potential impacts of the Environmental Protection Agency’s proposed carbon emissions rule in response to a request from the Organization of PJM States Inc. (OPSI).
In a letter to PJM CEO Terry Boston, OPSI said it would like the analyses based on several scenarios, including one that assumes a PJM-wide carbon price based on a “roll up” of EPA’s state emission targets and compliance with existing state energy efficiency and renewable portfolio standards. Other scenarios requested would include only renewable resources currently in the transmission queue or a 50% increase in natural gas costs.
Staff is conducting a production cost simulation and evaluating the reliability impacts from the potential loss of “at-risk” plants. Initial results are expected as soon as the end of the month.
Planners are also conducting an analysis of the potential loss of Exelon’s Byron, Quad Cities and Clinton nuclear plants at the request of the Illinois Commerce Commission. Exelon has said it may be forced to close some of its Illinois nuclear fleet because of low energy and capacity revenues. (See Exelon in Lobbying Push to Save Ill. Nukes.)
The ICC’s request asked PJM to calculate the potential impact on wholesale energy prices and the need for transmission improvements. Initial results are expected in mid-October.
