William R. Mayben will retire next year after serving seven years on the PJM Board of Managers. PJM announced last week that Mayben would remain in his position until a successor is named at the May 2015 PJM Annual Meeting.
The Nominating Committee will seek a successor to serve the remainder of Mayben’s term, which expires in 2016. Under the PJM Operating Agreement, the replacement must have “expertise and experience in the operation or concerns of Transmission Dependent Utilities.”
Mayben was president and CEO of the Nebraska Public Power District from 1995 to 2002. Before heading the Nebraska PPD, he spent more than 30 years at R.W. Beck & Associates, an engineering and management consulting firm, rising to managing partner and CEO.
A 1962 electrical engineering graduate of the University of Colorado, he is a former member of the board of directors for both the American Public Power Association and the Large Public Power Council.
The joint operating agreement between PJM and Duke Energy Progress should be revised to reflect the 2012 merger between Duke Energy and Progress Energy and eliminate Progress’ favored treatment on interchange pricing, according to the RTO’s Independent Market Monitor.
The Monitor filed a protest Oct. 24 urging the Federal Energy Regulatory Commission to reject PJM’s revisions to the agreement. The Monitor said PJM should terminate the existing agreement and negotiate a new one.
“The merger plainly creates material changes to the circumstances reflected in the PJM-Duke Progress JOA, yet there is no indication that any negotiation has occurred,” the Monitor said. “The assumptions reflected in the current PJM-Duke Progress JOA no longer apply, and the proposed revisions are not an adequate response.”
Progress Energy Carolinas (PEC) — now Duke Energy Progress — which serves the western portion of North Carolina, signed the JOA with PJM in 2005.
With the merger, Duke assumed control of most of North Carolina’s utility business, as its subsidiary Duke Energy Carolinas (DEC) already covered the state’s eastern portion. The two utilities signed a joint dispatch agreement as part of the merger.
This creates a conflict with PJM’s Operating Agreement, according to the Monitor.
PJM has a single pricing point for all transactions south of its territory that establishes default prices between the RTO and other balancing authorities. In 2010, however, PJM and Progress revised their JOA to allow for special dynamic pricing between them. PJM’s OA (Section 2.6A) allows dynamic pricing with a neighboring balancing authority as long the latter does not trade energy with other neighboring balancing authorities. The single pricing point was established to prevent market participants from gaming price differences between interface pricing points by scheduling transactions that do not reflect true system flows, the Monitor said.
“Because the [joint dispatch agreement] provides for joint optimization between the Duke Progress and DEC balancing authorities, there is, by definition, a continuous flow of energy transactions between the balancing authorities,” the Monitor said.
The Monitor urged FERC to direct PJM and Duke to create a new JOA and, in the meantime, apply OA rules concerning joint dispatch to transactions with the two utilities.
The Monitor’s complaint reprises an argument it has been making since at least 2010, when it criticized PJM for “singling out PEC for special treatment at the expense of movement forward to create a comprehensive approach to seams at PJM’s southern boundary.” (ER10-713) (See FERC Rebuff of Duke Could Mean Closer Ties with PJM.)
PJM’s revised JOA updates the name of Progress Energy Carolinas and adds an appendix that provides uniform transmission line identifiers for both parties, in compliance with a North American Electric Reliability Corp. reliability standard (TOP-002-2.1b, R18).
Jason Barker of Exelon (L) looks skeptical, James Wilson, a consultant to state consumer advocates (R), appears amused, as Tom Graves, of Burns & McDonnell speaks to the PJM Market Summit on the RTO’s response to extreme weather.
PHILADELPHIA — Operational challenges and costs may limit the ability of generators to obtain the level of reliability envisioned in PJM’s Capacity Performance proposal, power industry experts said last week.
At the PJM Market Summit in Philadelphia, industry officials cited a range of obstacles to PJM’s plan, which some called an overreaction to the generator outages of January:
Operators of advanced turbines are reluctant to add dual-fuel capacity because of higher maintenance costs and limited operating history.
Neither turbine manufacturers nor insurers are offering a way for generators to insulate themselves against nonperformance risk.
Dual-fuel generators lacking fuel storage tank farms would likely need to be connected to a fuel terminal.
Force majeure clauses common in the natural gas industry mean even generators with firm transportation contracts may be exposed to nonperformance penalties.
Megan Parsons, development section manager for engineering and construction management firm Burns & McDonnell, said PJM’s emphasis on backup fuel capabilities will benefit reciprocating engines and aeroderivative and E-class turbines. But owners of advanced F-, G-, H- and J-class turbines have been hesitant to employ dual-fuel capability because of higher maintenance costs and limited operating history.
“Because it’s expensive to test fuel oil, none of the OEMs [original equipment manufacturers] have lots of fuel oil test hours and don’t expect to get a lot of fuel oil test hours,” she said. “So it’s going to be a bit of time before the industry really knows what those long-term maintenance implications are. All of the OEMs have or are planning fuel oil testing. They have tested successfully, reliably. But inherently with higher firing temperatures there are higher maintenance implications.”
Combined-cycle “units are very, very large and use a lot of fuel,” added Parsons’ colleague, Tom Graves, senior project manager for Burns & McDonnell. “You’re looking — for 48 hours of operation — [at] a 5 million gallon tank. That’s a lot of money and capital sitting there unused.”
150-MW Peaker Analysis
Graves said an analysis he performed for a PJM generation owner found that retrofitting an F-class simple-cycle unit would cost $50 to $100/kW, or $7.5 million to $15 million for a 150-MW peaking unit. The 1 million gallons of fuel oil needed to run for 48 hours would cost about $4 million, he said.
“So you’re potentially $12 [million] to $20 million into this thing before you ever ran a single hour,” he said. “Forget the logistics of getting 7,500-gallon trucks to your facility to refill 300,000 gallons of usage over a single day. That’s 45 trucks a day. You have to be close to a terminal and you’re going to have to have a wholesaler or marketer that can provide 45 trucks worth of diesel in a very short period of time … so you really are probably looking at a pipeline connection to a terminal.”
In addition, generators may be able to operate on oil for only 40 or 50 hours annually without triggering the Environmental Protection Agency’s new source review rules, he said.
In comparison, Graves said, a firm gas contract for $8 to $16 per dekatherm-day would cost $2.5 million to $5 million annually.
Firm Gas Option
PJM’s Mike Bryson, executive director of system operations, acknowledged fuel storage is a big challenge.
“It’s one of the reasons that coming up with a firm gas alternative may still be financially better off,” he told the summit audience of about 60 at the Philadelphia Sheraton Downtown hotel. “We want to talk to the gas industry and say, ‘We need to figure this out. You may not have the product now but we need to come up with a product.’ Dual-fuel is very expensive.”
Force majeure provisions
Even generators with firm gas transportation contracts may be exposed to nonperformance penalties under PJM’s proposal because pipelines generally limit their liability with force majeure provisions.
Bryson said force majeure is one of the most contentious issues surrounding PJM’s proposal.
“I don’t even know if we have one staff position on force majeure. We might actually have three. So we haven’t figured it out,” he said. “We’re listening to people [on] this. That’s a big issue that the board needs to decide on in a couple of weeks.” (See related story, Coalitions Make Their Cases to PJM Board.)
Scott Harvey of FTI Consulting said gas generators are unlikely to contract for firm delivery.
“Go back and look at what [the Federal Energy Regulatory Commission] did after the gas crisis in California where there were gas-fired generators that had firm contracts for gas. And when FERC was looking for money to cushion the shock on the California ratepayers they took that money out of those contracts,” Harvey said. “No CEO in their right mind should ever sign a firm gas contract if they’re a merchant generator.”
Harvey said a cheaper alternative might be to offer industrial customers incentives to release their gas in a one-in-24-year weather event such as January’s polar vortex.
“How about once in 24 years we shut down 40 industrial plants for two days and make all that gas available? How does the economics of that lost production compare to the cost of building 12 new gas pipelines?” he asked. “There’s a lot of flexibility if you allow the market to work.”
Insurance, Warranties
Officials said neither turbine manufacturers’ warranties nor insurance offers enough coverage to protect generation owners from nonperformance penalties.
Parsons said turbine manufacturers offer some warranty coverage for unplanned events. “So I think there is an appetite for some of that. In general it gets to be: ‘Do the OEMS want to be an insurer?’ As of yet, fully, I think the answer has been ‘no.’”
Normal business interruption insurance comes with 30- or 60-day financial deductibles, said Jason Kahan, vice president with Energy Investors Funds of New York.
“I don’t think you’re going to be able to find an insurance product that’s going to [protect] you” if your plant is out of service for one or two peak days in winter or summer, he said. “What’s that number for a large combined-cycle facility? $100 million? I don’t think [coverage] exists and without a doubt the insurance market isn’t deep enough now.”
“With these complex types of products and these kinds of numbers, you’re buying a right to litigate. That’s what you’re buying,” said attorney John J. McAleese III, of McCarter & English in Philadelphia. “You’re not actually buying insurance. They’re in the premium-collection business. It pays for them to litigate before they pay” large claims.
Kahan said PJM’s rules will make financing new generation more complicated and expensive.
“Banks are going to require either higher interest rates or more equity as part of the overall capital structure. It’s going to further drive capacity prices up because if you want to build it you’re going to have a higher [rate of return] because of that risk premium.”
Overreaction?
Some summit speakers said PJM’s proposal is an unnecessarily expensive response to a very unusual weather event.
Graves called PJM’s proposal “a bit of a knee-jerk reaction,” saying he sees the locational value of Capacity Performance as similar to that for black start capacity.
He noted that gas-supply problems during January were limited to areas with insufficient pipeline capacity. Focusing on location-specific fuel-supply problems could improve reliability at a much lower cost, he said.
“There’s specific regions on the grid where black start generation is valuable and there are other locations where it provides no value. There are going to be specific places on the grid where [firm fuel] products are valuable and [others] where they aren’t. Six, eight months isn’t enough time to really understand the issue and plan for it.”
James Wilson, consultant to state consumer advocates, said PJM failed to exploit energy conservation measures that could have provided breathing room in January.
Wilson said PJM’s product will create “a private club with very strict eligibility and entrance requirements” and new market power problems that cannot be effectively mitigated.
“Sellers will have numerous reasons for not offering Capacity Performance, or only offering it including a lot of investment and risk in their offer. I really don’t think PJM or the Market Monitor is going to be in the position to go through and verify and critique and disagree with those reasons,” he said. “Only a small amount of Capacity Performance eligible — or potentially eligible capacity — really has to be withheld to [make] the Capacity Performance price very high.”
Wisconsin Energy and Integrys Energy Group told the Federal Energy Regulatory Commission last week that their merger would not result in excessive market power and higher rates in Michigan’s Upper Peninsula, as state officials have claimed.
In their Oct. 28 filing (EC14-126), the companies sought to counter claims by opponents, including Michigan Gov. Rick Snyder, that Wisconsin Energy’s $9.1 billion acquisition of Chicago’s Integrys would stifle competition.
Snyder and Michigan Attorney General Bill Schuette told FERC in an Oct. 17 protest that the companies failed to analyze the relevant geographic market in determining market power, noting that most of the utilities’ generation is in the Wisconsin and Upper Michigan System (WUMS). (See Michigan Gov.: Wisconsin Energy-Integrys Merger Could Stifle Competition.)
While acknowledging that most of their generation capacity is located in the WUMS region, the utilities said the commission has not identified default markets within the MISO territory that are required to be analyzed in a competition analysis.
Less Congestion
Nevertheless, the utilities said they hired two analysts to evaluate whether WUMS should be evaluated as a separate geographic market. The utilities said the analysts’ findings show that transmission expansions and new generation “significantly” reduced transmission congestion into WUMS since 2007.
They also said additional transmission projects are planned for the area before the merger is scheduled to close in 2015.
“In addition, net generation capacity in WUMS has increased to the point that MISO projects a capacity surplus of 700 MW in 2016” for the zone, they wrote. “All of this evidence demonstrates that there is less reason to consider WUMS as a separate geographic market today than when the commission made its prior rulings” on the region.
The utilities presented data that they said show that prices in WUMS are lower than average prices in MISO during most periods.
Justice Department Review
The utilities, with more than 4.3 million gas and electric customers in the Midwest, said the U.S. Department of Justice closed its investigation into the competitive effects of the merger on Oct. 24.
One of the concerns raised by Michigan state officials is that the surviving utility, Wisconsin Energy, would gain a 60% ownership interest in the area’s only transmission system operator, American Transmission Co.
In their FERC filing, Wisconsin Energy and Integrys countered that ATC has transferred control over its transmission facilities to MISO. “As a consequence, regardless of what entities are deemed to control ATC and ATC management, ATC’s transmission facilities are under the control of MISO, and nothing about the merger will change that fact,” they wrote.
Facing pushback to its carbon-reduction proposal, the Environmental Protection Agency last week signaled a willingness to consider a slower shift from coal to natural gas generation and a regional approach to increasing renewables use.
Having already received 1.5 million comments in response to its “Clean Power Plan,” the EPA on Oct. 28 issued a 60-page notice of data availability (NODA), which invited feedback on “the compliance trajectory or glide path of emission reductions from 2020 to 2029, certain aspects of the building block methodology and the way the state-specific CO2 goals are calculated.”
EPA’s June proposal seeks to reduce power sector carbon emissions by 30% from 2005 levels by 2030. Comments on the NODA and the original plan are due Dec. 1.
“The additional information is not about making the proposal more or less stringent. I would caution anyone against reading too much into this,” Janet McCabe, acting assistant administrator for the Office of Air and Radiation, said in a press call last week.
Nevertheless, the questions the agency posed suggest changes it may incorporate in its final regulations in June 2015 to make it more palatable to states and the power industry.
Coal-to-Gas Shift
In public hearings and written comments, the agency heard objections from coal-heavy states that said the interim goals in the proposed regulation would require them to shift to natural gas generation faster than the infrastructure can be built. Critics also said it would result in massive stranded costs and could threaten electric reliability by forcing the retirements of coal plants that recently received environmental upgrades to meet previous EPA regulations.
The agency conceded in the NODA that compliance “will be difficult for at least some states to reasonably achieve in that time frame.”
It asked for comments on possible adjustments that would allow a more gradual phase-in of re-dispatch from coal to gas between 2020 and 2029. The EPA said its intent is to come up with “a reasonable glide path” for states to reach compliance by 2030.
One idea is to develop a phase-in schedule that would take into account whether natural gas pipeline expansions or new electric transmission is needed to support heavier use of gas-fueled generation.
The agency also asked for comment on whether it should consider the book life of pollution-control retrofits in addition to the 40-year book life it assumes for coal generators.
The NODA also cited concerns of some stakeholders that the proposed rule creates a disparity between states with little or no natural gas generation capacity and those with significant amounts of such capacity that’s not being used, which could result in “distortions” in regional electricity markets. The NODA suggests the possibility of determining appropriate levels of generation shift in a regional manner, such as basing it along RTO territories.
“Some stakeholders have suggested that these disparities could be reduced by increasing the obligation of those states with little or no [natural gas combined-cycle] generating capacity to employ natural gas use beyond what the EPA included in the proposed rule,” the agency said.
That could include the construction of new combined-cycle units and additional co-firing of natural gas at existing coal units. The EPA said commenters have said that co-firing would reduce nitrogen oxides and sulfur dioxide, potentially reducing the cost of controlling those pollutants. Co-firing also could allow units to ramp up and down more quickly so a generator could take advantage of low fuel prices.
Regional Approach to Renewable Energy
The NODA suggests a regional approach could also be applied to the renewable energy component of its plan to include opportunities for cross-state renewable imports. “Under this approach, a state’s goal would be informed by the opportunity to develop out-of-state RE resources as part of its state plan,” the EPA said.
McCabe noted that markets for renewable energy are not confined within single states. “We wanted to be reflective of how these markets actually work,” she said.
Base Year
One of the biggest gripes among states and power industry officials has been the EPA’s proposed use of 2012 as the base for calculating interim and final goals. Some commenters contend that emissions were unusually low that year because of a lackluster economy.
The NODA includes emission data for 2010 and 2011 and invites comments on whether it should use a different single data year or the average of a combination of years to calculate the fossil fuel emissions rates used in state goal calculations.
“This is not intended to signal any particular direction we’re going in,” McCabe said.
RTO Concerns
Many stakeholders have pressed RTOs to express their opinions on the proposed rule, particularly its impact on resource adequacy:
A PJM official said last month that 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 Standards (MATS). (See State Officials Challenge EPA Assumptions on Carbon Rule.)
NYISO CEO Stephen G. Whitley told RTO Insider last week that the ISO will file its own comments. “We just had a meeting with [EPA Administrator] Gina McCarthy that was very productive. EPA has shown that it is willing to listen, as it recently did with MATS.”
ISO-NE hasn’t decided whether to file. “We are looking at the rules and evaluating whether we will be submitting our own comments,” said spokeswoman Lacey Girard.
MISO said it has had “overwhelming stakeholder support” to file comments with the EPA. MISO plans to post an outline of its proposed comments for stakeholders’ review this week. Hoosier Energy said MISO should quantify the costs of heat rate improvements and new electric transmission and natural gas infrastructure that will be required. Hoosier and Ameren urged MISO to identify reliability concerns resulting from coal plant retirements. Ameren also suggested the ISO address the challenges of integrating increasing amounts of wind power. Calpine, in contrast, told MISO it should not file comments. “Should MISO file comments, they should limit any comments to fact-driven analysis and not provide opinions that indicate any preference by MISO,” Calpine said, according to a MISO summary.
New York-New England Correspondent William Opalka contributed to this story.
The Nuclear Regulatory Commission is increasing its oversight of Exelon Nuclear’s Calvert Cliffs Unit 2 after the company discovered that new instrumentation at the Maryland plant caused inaccurate radiation calculations that could have initiated a premature emergency declaration.
Exelon personnel in March noticed that new monitors installed five months earlier on the main steam line required recalculated thresholds for different levels of emergency. Exelon notified the NRC and fixed the problem.
“Nuclear power plant operators are always expected to err on the side of caution,” said David Lew, acting NRC Region I administrator. “But this is a case where an emergency declaration could have been made prematurely, triggering unnecessary responses.” The NRC credited Exelon with repairing the problem but criticized the company for allowing it to go unnoticed for five months.
Exelon argued that the mistake should have been classified a “green,” or very low safety, issue. The NRC determined that it was a more serious “white” issue, and it will step up oversight.
Wellinghoff Says Microgrids Key to Protecting System from Attacks
Jon Wellinghoff
A system of microgrids would protect the bulk power system from calamity in the event of a physical or cyber attack, former Federal Energy Regulatory Commission Chairman Jon Wellinghoff told the GreenBiz Group’s VERGE conference last week.
“From everything I have seen, our grid is in really miserable condition from the standpoint of physical security overall,” Wellinghoff said. The answer is to diversify the system with microgrids, “so if they take down one node, it’s not going to cascade,” he said.
“Microgrids ultimately are where we need to move, to a distributed type of system, if we are ever to put out a defensible system that, in fact, can be sufficiently secure to provide us the level of reliability we all need for our businesses and homes,” Wellinghoff said.
The Federal Energy Regulatory Commission gave conditional approval of Calpine’s purchase of the Fore River generating station near Boston from Exelon Generation.
The agency ruled that the sale is “consistent with the public interest,” but it set a number of conditions, such as retaining FERC’s authority over rates and other costs. The conditional approval means that the commission sees no market power issues with the sale.
Calpine announced in August that it was purchasing Exelon’s 809-MW power station in North Weymouth, Mass. The deal, expected to close by the end of the year, would make Calpine the eighth-largest generator in New England, up from 13th.
Constitution Pipeline Impact Study Released by FERC, Gets OK
The Federal Energy Regulatory Commission released the final environmental impact study for the proposed Constitution Pipeline to run 124 miles from Pennsylvania’s shale-gas fields to New York. The 30-inch pipeline would have “some adverse environmental impacts,” but the impacts would be mitigated if the pipeline company sticks to its plans and FERC’s recommendations, the study said.
Final FERC approval in the form of a certificate of public convenience and necessity, and other state and local approvals, are expected next year. The pipeline is designed to carry 650 million cubic feet of gas a day to Northeastern markets. It is a joint venture among Williams Co., Cabot Oil & Gas, Piedmont Natural Gas and WGL Holdings.
Atlantic Coast Pipeline Files to Start FERC Approval Process
Dominion on Friday asked the Federal Energy Regulatory Commission for permission to start the pre-filing process for its 550-mile Atlantic Coast Pipeline to deliver natural gas from Appalachian shale-gas fields to North Carolina.
The four companies that want to build the $4.5 billion to $5 billion pipeline — Dominion, Duke Energy, Piedmont Natural Gas and AGL Resources — say it is needed to meet demand, especially from proposed natural gas-fired power plants. They point to a more than 450% increase in demand for gas-fired generation in North Carolina between 2008 and 2013 and a 123% increase in Virginia.
Pre-filing with FERC starts a process of government and public input, as well as initiating the numerous studies the project will need. The proposed pipeline would run from West Virginia, through Virginia and into North Carolina. Dominion said it expects to get all approvals by 2016 and complete construction in 2018.
DOE’s Rules Take Longest to Get White House Review
The White House Office of Management and Budget takes nearly seven weeks longer to review new rules from the Department of Energy than those of any other federal agency, according to a Bloomberg BNA study.
On average, the reviews by OMB’s Office of Information and Regulatory Affairs (OIRA) of Energy Department proposals take 154 days. Ahead of it is the Pension Benefit Guaranty Corp., with an average of 109 days, with the Department of Labor coming in at 107 days.
“These long delays in rules are important in terms of improving public protection,” said Ronald White, director of regulatory policy for the Center for Effective Government, a nonprofit group that was previously called OMB Watch. “It delays the benefits, and in a lot of cases we also know that OIRA reviews weaken the rules from what the agencies propose.”
The agency offered no explanation why the Energy Department rules take more time. “Our goal is to maximize the effectiveness and benefit of the rules we complete,” it told Bloomberg. “We have made it a priority to complete reviews in a timely manner.”
5 Companies to Get $13 Million to Develop Advanced Reactors
The Department of Energy is distributing $13 million to five companies to help them design, construct and operate advanced nuclear reactors. The awards are part of the Obama Administration’s Climate Action Plan and a DOE program started last year.
The cost-sharing grants to address technical challenges for next-generation nuclear reactors were awarded to:
REVA Federal Services, working on liquid metal-cooled reactors.
GE Hitachi Nuclear Energy, working on risk assessment practices.
General Atomics, building and testing complex silicon carbide structures.
NGNP Industry Alliance, investigating gas reactor post-accident heat removal.
Westinghouse Electric, developing thermo-acoustic sensors for sodium-cooled fast reactors.
Two years after the merger of Progress Energy and Duke Energy, the Federal Energy Regulatory Commission issued its final decision on the transaction. It also threw out all remaining rehearing requests.
The two companies had filed for reconsideration some of the conditions FERC set for the merger, saying they were too restrictive. The commission also denied petitions from a number of organizations — including the town of New Bern, N.C., and the Florida Municipal Power Agency — that said the commission had been too easy on Duke and Progress.
Nearly 100 climate change protestors blockaded the headquarters of the Federal Energy Regulatory Commission yesterday, snarling traffic on First St. N.E. About 25 protesters were arrested. Among those participating were marchers who arrived in Washington following a cross-country walk from Los Angeles.
The protestors cited a variety of climate-related and environmental issues, including FERC’s approval of the Cove Point LNG project in Maryland.
Casino industry woes in Atlantic City are spreading to the power-generation industry.
Pepco Holdings Inc. wrote down the value of a district heating and cooling plant in the New Jersey resort from $83 million to $30 million because of “significant adverse changes in the financial condition of its customers and the business climate in Atlantic City.”
Trump Entertainment Resorts, which declared bankruptcy in September, owned two casinos served by the plant: the now-closed Trump Plaza and the Trump Taj Majal, which is expected to close in December. Pepco inherited the plant when it bought Atlantic City Electric and Delmarva Power & Light in 2002.
Xcel’s Midwest Hydro Fleet Sets Sept. Production Record
Xcel Energy’s hydro fleet in Wisconsin and Minnesota set a September production record thanks to above-average rainfalls, the company said.
The company’s 19 hydro plants put out 130,537 MWh in September, eclipsing a record set in 2002 by 11,598 MWh. The company credited large amounts of rain in the Upper Midwest.
“Seven of our last nine months have been significantly above the 10-year average for hydro generation,” said Scott Crotty, manager of Xcel’s hydro operations. Hydro makes up about 8% of Xcel’s total generation. The company said more than half of the electricity it supplies customers in the Upper Midwest comes from carbon-neutral hydro, wind, nuclear or biomass sources.
DTE Completes $2 Billion in Upgrades at Michigan Plant
DTE Energy says its Monroe Power Plant in Michigan is now one of the cleanest coal-fired power stations in the country after it completed emission-control upgrades costing nearly $2 billion.
The upgrades at the 3,400-MW plant included new selective catalytic reduction, flue gas desulfurization equipment and construction of two 580-foot tall chimneys. The improvements will cut NOx emissions by 90%, SOx by 97% and mercury emissions by 75% to 90%.
Monroe, on the western shore of Lake Erie, was built in the 1970s. It is the largest plant in Michigan and the fifth-largest coal-fired plant in the U.S.
Southern’s Kemper Plant to Cost More Time and Money
Another new power plant designed to employ carbon-capture technology is racking up cost overruns.
Southern Co. says its Kemper plant in Mississippi will cost $6.1 billion, up an additional $496 million, and it is pushing back the completion date from June 2015 to March 2016. The plant’s initial cost was $2.8 billion and it was projected to begin operations in 2013.
The company said that the overruns will reduce after-tax quarterly profit by $258 million. Southern subsidiary Mississippi Power is also planning to ask the Mississippi Public Service Commission for permission to pass $167 million on to customers.
The Kemper plant is designed to convert soft lignite coal to gas that will fuel its boilers. Carbon dioxide from the combustion process is to be captured for industrial uses or storage underground.
Similar plants are also experiencing trouble. Duke Energy’s Edwardsport, Ind., plant, which uses coal gasification technology, suffered from construction delays and cost overruns. And FutureGen, a government-backed project in Illinois, was announced in 2003 and still isn’t operational.
We Energies ‘Willing’ to Invest in New Plant to Help U.P. Shortage
Wisconsin Energy’s CEO Gale Klappa said the company is “willing to be an investor” in a new generation facility to ease an energy shortfall in Michigan’s Upper Peninsula.
The company’s Marquette plant on the Upper Peninsula is operating at a loss under orders from MISO to preserve system reliability. Wisconsin ratepayers balked at paying a premium to support the plant, and the company’s We Energies subsidiary had said it wanted to retire the plant, which would leave a generation capacity shortfall in the Upper Peninsula. The company is facing a similar situation with its Presque Isle power plant. (See related story, Michigan: FERC Rules Favor Transmission, Will Increase Costs.)
We Energies will need approval from Michigan regulators for its buyout of Integrys Energy Group, and Klappa said the company would be willing to invest in a 250- to 350-MW natural gas combined-cycle plant as part of its efforts to secure Michigan’s approval for the $5.8 billion Integrys buyout. (See related story, Integrys, Wisconsin Energy Reject Michigan Claims on Merger.)
Invenergy to Build 1,300-MW Plant Near PPL’s Susquehanna-Roseland Line
Chicago-based Invenergy has filed with the Pennsylvania Department of Environmental Protection to build a 1,300-MW combined-cycle plant near Jessup, Pa.
The Lackawanna Energy Center would be the state’s second-largest natural gas-fired power plant, after PPL’s 1,722-MW Martins Creek plant in Northampton County. The plant will have three gas-fired turbines and a single steam turbine, according to company filings. Construction could begin as soon as June and be completed by 2017.
The availability of shale gas from the Marcellus field has spurred a flurry of power plant construction in Pennsylvania. Panda Power has two plants under construction and others are in the planning stages.
Green Mountain Gets License Extension for Vermont Hydro
The Federal Energy Regulatory Commission has granted Green Mountain Power 40-year license extensions for three hydro stations on Otter Creek in Vermont.
The licenses will allow Green Mountain to upgrade the plants from 14.4 MW to 22.8 MW. The dams are at Proctor Falls, Belden Falls and Huntington Falls. The upgrades will cost about $19 million, company officials said. Green Mountain bought the dams from Vermont Marble Power in 2010.
We Energies Rate Supporter Signatures May Be Fraudulent
Three organizations battling We Energies on a rate case involving solar energy have challenged the validity of petitions supporting the rate increase.
The Environmental Law & Policy Center, RENEW Wisconsin and The Alliance for Solar Choice asked the Wisconsin Public Service Commission to investigate whether 2,500 people actually signed the petitions. The organizations say many of the signatures were of those who didn’t know their names and addresses had been used and some who actually oppose the rate hike. The petition was filed by the Consumer Energy Alliance.
According to opponents, We’s proposal cuts the benefits of energy efficiency and solar energy and creates obstructions for solar suppliers other than We.
Pocomoke City’s Solar System Largest Municipally Owned in Md.
Pocomoke City’s 2.1-MW solar array will be the largest municipal photovoltaic system in Maryland when it goes on line in December.
“The completion of this large solar project in Pocomoke City will make the southern Eastern Shore one of the leading solar areas in the state,” said state Delegate Norman Conway, who represents Worcester and Wicomico Counties. “These solar systems are helping our regional economy by allowing our local governments, educational institutions, businesses and homeowners to generate substantial savings on their electricity bills.”
The 6,150-panel array will offset 2,067 tons of carbon dioxide annually. The system is expected to save the city more than $37,000 a year in energy costs.
PSE&G Starts Building Another Solar Plant on Closed Landfill
Construction has started on an 11-MW solar project atop a closed landfill, the third such energy project undertaken by Public Service Electric & Gas. When it goes on line next spring, PSE&G will have more than 31 MW of solar generation at landfills in New Jersey.
The latest project, at the closed Kinsley Landfill about 15 miles south of Philadelphia, will cover about 35 acres of the 140-acre site. Almost 37,000 panels will generate enough electricity for 2,000 average-sized homes.
The projects are part of the company’s Solar 4 All program, which installs grid-connected solar panels on landfills, utility poles, parking lots, rooftops and other sites. Plans call for developing 42 MW more of capacity in the next few years.
Delmarva Power Building 25-Mile 138-kV Transmission Line in Md.
Delmarva Power & Light is spending $29.6 million to rebuild a transmission line between the Maryland Eastern Shore towns of Denton and Millington.
Steel poles between 95-feet and 125-feet tall that can withstand hurricane-force winds will carry the line. They will replace poles and wire built in 1955. The company said work on the project will begin in February 2016 and be completed by June 2017.
Demand Response Panel: (left to right) Greg Poulos, EnerNOC; Howard Learner, Environmental Law and Policy Center; Frank Lacey, Comverge
PHILADELPHIA — EnerNOC and Comverge executives last week expressed confidence that the demand response industry will continue to grow despite the appellate court ruling that threatens its continued participation in energy and capacity markets in PJM and other RTOs.
“It does put some constraints on us, but we are still signing up lots of customers,” Greg Poulos, manager of regulatory affairs for EnerNOC, told the PJM Market Summit conference.
Ruling in a challenge by the Electric Power Supply Association (EPSA), the D.C. Circuit Court of Appeals May 23 voided the Federal Energy Regulatory Commission’s Order 745, which set compensation rules for DR. The court said it improperly intruded on state jurisdiction.
In response, PJM on Oct. 7 proposed eliminating DR as a capacity supply resource, suggesting load-serving entities instead offer DR and energy efficiency to reduce their capacity obligations. (See EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans.)
Frank Lacey, vice president of regulatory and market strategy for Comverge, said PJM’s proposal was fatally flawed, in part because it depends on LSEs.
“The LSEs, quite frankly, are EPSA,” he said, noting the group’s membership includes units of utilities such as Exelon, PPL and Public Service Enterprise Group as well as independent power producers such as Calpine and NRG Energy. “The generators don’t like demand response. They’re trying to get demand response out of the market” and boost prices.
Lacey said even well-meaning LSEs won’t be able to aggregate resources, a “core function” of curtailment service providers such as EnerNOC and Comverge.
“Close to 100% of the DR will not be available,” Lacey said. “It was not a well thought out solution.”
Howard Learner, executive director of the Chicago-based Environmental Law and Policy Center, predicted the Supreme Court will review the D.C. Circuit order and reverse it, making PJM’s “workaround” unnecessary.
“If the Supreme Court takes the case they will likely overturn. That’s how appellate litigation works,” Learner said.
New York and federal energy regulators will study the state’s troubled capacity market at a technical conference in Manhattan Wednesday.
It will be the first-ever joint technical conference for the New York Public Service Commission and the Federal Energy Regulatory Commission. It was scheduled after a contentious few months in which FERC approved a capacity zone north of New York City that has led to higher electric rates and a court challenge from the PSC.
The conference will be held from 9 a.m. to 4 p.m. at the New York Institute of Technology Auditorium, located at 1871 Broadway, between 61st and 62nd Streets. The conference will be webcast and transcribed.
FERC approved the capacity zone, which was proposed by NYISO, as a way to attract new generation to the area.
The conference will include sessions to discuss recent capacity market performance and ways to attract investment in resources and infrastructure. Among the speakers will be representatives from the state’s independent power producers, utilities and retailers.
“I look forward to this timely discussion of how the NYISO capacity markets work to ensure reliability and just and reasonable rates, and also to hearing about New York’s REV program,” FERC Chairman Cheryl LaFleur said. “It is critical to ensure that centralized capacity and energy markets send correct signals to support the procurement and retention of resources needed to deliver reliable energy.”
Exelon is selling its ownership interest in the Keystone and Conemaugh coal-fired power plants in Pennsylvania, leaving it with just one coal-fired plant — a 25% interest in a waste coal generator.
Exelon once had extensive coal-fired holdings but has either sold or retired them over the years as it concentrated on new gas-fired generation and its massive nuclear fleet. Now, including Keystone and Conemaugh, just 4% of Exelon’s generation portfolio is from coal.
The company announced the sale on Wednesday in a section in its earnings release, saying it would bring in approximately $475 million — $418 million after taxes — which the company will use in its acquisition of Pepco Holdings Inc.
Exelon has a 31.32% interest (535.8 MW) in the Conemaugh plant, a coal and oil plant in New Florence, Pa., northeast of Pittsburgh. It owns 41.99% (720 MW) of Keystone, a coal and oil plant in Plumcreek Township, Armstrong County – the heart of Pennsylvania’s coal country.
The other companies with ownership interests in the Keystone and Conemaugh plants are Public Service Enterprise Group, NRG Energy and PPL.
Exelon spokesman Robert Judge said the company’s shares are being sold to ArcLight Capital Partners, a private equity firm based in Boston. ArcLight has spent more than $11 billion on energy assets since 2001, including investments in wind, waste coal, coal, natural gas, oil and hydro plants, from Germany to the U.S.
Judge declined to say whether the sale signals the end to Exelon’s coal history. The sales were not mentioned during the third-quarter earnings call Thursday.
Judge said the sale is expected to close early next year. When that happens, the only coal-fired generation Exelon will own is a 25% interest in Colver, a 102-MW waste coal plant in Cambria County, Pa.
Exelon retired Unit 1 of its coal-fired Eddystone Generating Station near Philadelphia in 2011 and Unit 2 in 2012. The two units produced about 700 MW. Units 3 and 4 remain in operation and use oil or natural gas. It retired a 144-MW coal unit and a 201-MW dual-fuel unit at Cromby Generating Station near Phoenixville, Pa., in 2011.
William R. Mayben will retire next year after serving seven years on the PJM Board of Managers. PJM announced last week that Mayben would remain in his position until a successor is named at the May 2015 PJM Annual Meeting.
