MISO on Thursday released the final scope of studies it will conduct through mid-2016 to help the RTO’s 13 states evaluate their compliance options under the Environmental Protection Agency’s Clean Power Plan.
The near-term analysis, expected to be completed by January, will look at the implications of various compliance paths. It will be based on the models used in prior analyses of the draft CPP with updates reflecting the final rule.
The mid-term analysis, expected to run through June, will use new models based on the most relevant compliance paths from the near-term study to determine likely resource buildouts and their locations under three separate futures. It will be the foundation for transmission development under the 2017 MISO Transmission Expansion Plan.
A long-term analysis, which will run through late 2018, will seek to develop transmission overlays needed to implement state compliance plans.
“MISO’s CPP study efforts over the next two [to] three years will create a bridge between the uncertainty and complexity that exists today and the modeling certainty needed for effective transmission overlay design,” the RTO wrote in its 10-page study scope.
The near-term study will model six scenarios, including a business-as-usual case, compliance via coal retirements and increased gas generation, and one weighted toward energy efficiency with a wind and solar buildout. The study will apply seven mass- and rate-based compliance options, both with and without interstate trading.
Preliminary Results in December
Bakke said MISO’s research team will have preliminary near-term analysis results ready to be presented at December’s Planning Advisory Committee meeting. “We’re trying to frontline as much as we can of this study into January and February,” said Jordan Bakke, senior policy studies engineer at MISO.
At last week’s PAC meeting, stakeholders expressed concern that the study could lead to an overwhelming output of information.
“We’re not going to lead with a mountain of data. We’re going to lead with the peak of the mountain,” Bakke responded.
MISO’s analysis, Bakke said, will examine the CPP from a system perspective, purposefully omitting an individual state breakdown. Bakke also called a study on reliability impacts under the rule “premature.” Instead MISO is asking for states to reach out with their plans so the RTO can begin applying them.
“When we move into our mid-term analysis, that’s when we get more detailed. For now, these are generic assumptions,” Bakke said. He added that the mix of rate-based and mass-based compliance in the study scope will be more nuanced when states come forward with their plans.
MISO isn’t putting itself under a deadline to qualify for the CPP’s Clean Energy Incentive Program, which rewards states with emission rate credits for “early action.” MISO said the program is “complex and will be further reviewed as the study progresses.”
States that delay coming forward with a plan or extension request beyond late 2016 will have a preset federal plan imposed on them in November 2017. State requests for extensions are due next September. (See Revised Clean Power Plan Allows More Time, Sets Higher Targets.)
“In the final rule, they’re really allowing states to do a wide variety of things… You have a fair bit of options in what your plan will look like,” said Mary Waight, one of MISO’s policy studies engineers, during a CPP informational workshop on Nov. 6.
AUSTIN, Texas — Environmental Protection Agency Administrator Gina McCarthy ventured into somewhat unfriendly territory last week at the National Association of Regulatory Utility Commissioners’ annual meeting to defend the Clean Power Plan and urge continued dialogue.
Calling the CPP the “biggest single step America has taken to deal with climate change and carbon pollution,” McCarthy told her keynote audience she fully expects the plan to be implemented.
McCarthy
“We know this rule will stand the test of time because it’s grounded in facts and science and firmly rooted in the Clean Air Act,” she said. “We’re confident we’ll withstand the litigation.”
“If you think we go into a corner when someone sues us, that’s not how we do it,” said McCarthy, her thick Boston accent making “corner” sound like “conner.”
“We will be sitting down with the states and the regions, and we’ll be working together. We’ll be answering questions the best we can. Every state knows that when they work with us to develop a state plan, we’ll come up with a plan that best meets their needs … while litigation continues elsewhere.”
EPA’s final rule calls for reducing power plant carbon dioxide emissions by 32% from 2005 levels by 2030. It calculates individual state targets ranging from a 7% reduction for Connecticut to a 47% cut for Montana. States would have to comply with interim goals between 2022 and 2030, but they have the option of asking for a two-year extension by Sept. 6, 2016.
Encouraging Extensions
McCarthy said the extension option was why the first step was specifically designed not to be a “heavy lift.”
“We are looking for states requesting extensions,” she said. “That lets us know which states are actively working this issue and what their timelines are. We’re confident the states have the flexibility and options to meet their goals. While we needed to recognize state targets, we also needed to recognize that electrons flow out of those state boundaries all the time.”
McCarthy encouraged state officials to continue working with EPA. “By doing that,” she said, “we will have done great justice to this rule and aligned our common missions going forward.
“Your part, in my opinion, remains an essential part of our success: to ensure the plan maintains reliability, to ensure our consumers are well served and to ensure energy remains affordable.”
Pushback
When the floor was opened to questions, McCarthy received pushback from several NARUC members.
Julie Fedorchak, chair of the North Dakota Public Service Commission, pointedly said the final rule was “anything but thoughtful,” noting her state’s emissions target went from an 11% reduction to a 45% reduction in the final plan.
McCarthy agreed North Dakota’s targets are “challenging” but said the final plan gives states a wider range of compliance options, such as regional trading programs.
“We’ve opened tremendous opportunities for flexibilities,” she said. “We hope that those flexibilities make this easier.”
Ryan Sitton, a first-term commissioner on the Railroad Commission of Texas, asked McCarthy what she thought was Congress’ role.
“It’s two-fold,” she responded, first pointing to the Clean Air Act and the authority it gave to EPA to regulate pollution. Secondly, McCarthy said, “Congress has an ability to provide solutions to climate change today, if they choose to do that.
“The president has made it clear if Congress wants to provide more flexibility than we’re working under [now], he would welcome that. Right now, that doesn’t seem to be where we’re at.”
Leakage
McCarthy and Joe Goffman, EPA’s associate assistant administrator and general counsel, nearly made it out of town without discussing “leakage,” in which states might use new gas plants to compensate for retired older plants without achieving the state’s emission reductions.
The concern for states is that stricter requirements for new plants may not allow them to build the newer plants. States that do build the new plants can set aside emissions allowances (for renewable energy and gas plants), but the plants would not be eligible for trading programs.
Appearing on a panel discussing multi-state solutions to the CPP, Goffman thanked the moderator and the audience for not asking about leakage before he left the stage early.
McCarthy was asked about leakage after her keynote address and jokingly responded, “Next question.”
Turning serious, she then said, “The short answer is my eyes glaze over when people start talking about leakage.”
McCarthy said she believes it’s important to “maintain the integrity of the reductions so they’re achievable. We don’t want to prejudge how it’s handled. We’re looking for continued engagement on this, so unfortunately, I don’t have a silver bullet on how this might be resolved.”
Michael Nasi, a partner with Jackson Walker, said the CPP incents the construction of combined-cycle gas turbines. However, as he pointed out, new fossil generation would “not be consistent” with the federal administration’s carbon-reduction goals.
“What’s to keep them from coming back to undercut [new-emissions standards]?” he asked. “How do you integrate new [intermittent] renewables when you need gas to balance them out?”
Mass-Based vs. Rate-Based
Goffman did contribute to his panel discussion on multi-state options, saying that whether to take a rate-based approach or a mass-based approach won’t be the first question asked.
“Don’t devise cures that induce disease,” he said. “Making the system work will take priority.”
A mass-based approach expresses the state’s goal as the maximum number of tons of CO2 that can be emitted during a specific time period. The rate-based approach sets the state goal based on pounds of CO2 per megawatt-hour of generation from covered plants. The mass-based approach limits total emissions.
The panel generally agreed a mass-based approach with a trading program offers more benefits than a rate-based approach. The latter can be more complex, and thus more expensive.
“It behooves all state interests, your regulators’ office and your governor’s office, to figure out what works best for your state,” said Doug Scott, vice president of strategic initiatives with the Great Plains Institute.
“The EPA did a remarkable job putting this together,” said Latham & Watkins’ Bob Wyman. “They didn’t take a position on which one they preferred.”
That said, Latham did note, “Rate-based looks backwards, it creates more transaction costs … in every other way, it’s less effective.”
Ameren reported third-quarter profits of $343 million ($1.41/share), a 17% increase over the St. Louis-based utility’s $293 million ($1.20/share) for the same period last year.
Ameren said warmer summer weather and a seasonal rate redesign helped boost revenue 9.8% to $1.83 billion. As a result, the company adjusted its guidance range to $2.58 to $2.68/share from $2.48 to $2.68, assuming normal temperatures for the remainder of the year. For the first nine months of 2015, Ameren reported net income of $601 million ($2.47/share), representing a $63 million year-over-year increase.
Ameren has made $886 million in capital expenditures in Ameren Illinois and Ameren Transmission Company of Illinois in the first three quarters, a 17% increase over the same period in 2014. Capital spending for Ameren Missouri dropped 19% to $444 million.
About $475 million in capital spending went to FERC-regulated electric transmission projects, including the construction of the $1.4 billion Illinois Rivers 345-kV transmission project that stretches 330 miles from Palmyra, Mo., to Sugar Creek, Ind.
“We continue to allocate significant amounts of capital to those businesses that are supported by modern, constructive regulatory frameworks to enhance good reliability and allow customers to better manage their energy usage, among other things,” CEO Warner L. Baxter said during a conference call.
Consolidated Edison of New York says it will end use of the “PSEG wheel” to route power into New York City if it doesn’t win relief in a cost allocation dispute with PJM.
In a letter last month to PJM, Con Ed said it may end its use of the wheel when its current term expires on April 30, 2017.
“Although Con Edison will not decide until April 2016 whether or not to extend the agreements, we do think it is appropriate to inform you … that Con Edison’s analysis based on currently available information does not demonstrate that the agreements should be extended,” it wrote.
In a separate filing with the New York Public Service Commission (12-E-0503), Con Ed said it had identified less costly alternatives to the wheel, in which Public Service Electric and Gas takes 1,000 MW from Con Ed at the New York border and delivers it through New Jersey to Con Ed load in New York City.
On Oct. 23, Con Ed also asked FERC to reconsider its request that it force PJM to recalculate the cost allocation for two transmission upgrades in northern New Jersey (EL15-18). Con Ed asked FERC to consider PJM’s response in the cost allocation dispute over the proposed Artificial Island transmission project, in which PJM acknowledged weaknesses in its distribution factor (PJM: Artificial Island Cost Allocation Appears ‘Disproportionate’.)
“PJM previously responded to Con Edison’s arguments by asserting that DFAX is appropriate for all transmission projects,” Con Ed wrote. “However, in its answer to the Artificial Island complaint, PJM now concedes that DFAX can produce ‘an atypical cost allocation when applied to unique projects,’ by which it means projects that are not needed to address transmission overloads.”
PSEG short circuit solution (Source: PJM)
PJM assigned Con Ed $629 million of the costs of a $1.2 billion transmission upgrade to address a short-circuit problem in the PSE&G transmission zone outside New York City. PSE&G was allocated $52 million of the cost. Con Ed was also assigned $51 million of PSE&G’s $100 million Sewaren storm-hardening project.
Con Ed says it should pay only $29 million for the two New Jersey projects. FERC rejected Con Ed’s request to change the cost allocations in June. (See Con Ed Rebuffed Again on NJ Cost Allocation Dispute.)
PSE&G, a unit of Public Service Enterprise Group, responded that a decision to terminate the wheel would not impact the cost allocation cases. There would be future consequences for planning of reliability projects over lines that extend from New Jersey into New York City, it added.
“We wish to make clear that if Con Edison does not extend the agreements, it may not rely upon the capability of the PJM or PSE&G systems … as a planning assumption in future reliability determinations,” the company wrote.
PSE&G and PJM transmission owners also asked FERC to reject Con Ed’s bid to use PJM’s Artificial Island filing in its cost allocation case.
They countered that the cases pose different technical challenges and that granting the motion would create an endless loop of interlocking disputes that would force FERC to continually revisit previously decided cost allocation decisions.
Con Ed’s peak load in New York’s five boroughs and Westchester County is more than 13,000 MW.
A power plant developer says it has met most requirements to repower a 106-MW coal-fired generator in the Finger Lakes region that has been closed for more than four years.
Greenidge Generation says it hopes to repower the facility with natural gas as a merchant plant by the middle of next year. To do so, it has asked state regulators for expedited approval of a 4.6-mile connection to the Empire Connector interstate gas pipeline. The petitions are before the New York Public Service Commission (15-E-0516, 15-G-0571, 15-T-0586).
An environmental group has challenged the company’s request for a certificate of public convenience and necessity, saying the plant is not needed and runs counter to the state’s clean energy goals.
“The public need for the pipeline is entirely dependent upon the public need for the generating station. Because [the developer] has failed to demonstrate a public need for reopening the generating station, there is no basis for determining that there is a public need for a new gas pipeline to the generating station,” the Committee to Preserve the Finger Lakes wrote.
The group also said the reopening of fossil fuel-fired power plants runs counter to the state’s Energy Plan released earlier this year that seeks to cut greenhouse gas emissions 40% below 1990 levels by 2030 and 80% by 2050. “These targets cannot be achieved if New York continues to bring fossil-fueled generating infrastructure online,” it said.
The group asked the commission to deny the request for expedited approval and instead conduct evidentiary hearings.
Greenidge disputes the environmentalists’ characterization of the public need. “The commission has consistently recognized that [merchant] facilities are in the public interest … where they have been shown to provide benefits in the form of increased employment, improved reliability and lower prices for electric energy and capacity throughout New York state,” it wrote.
It also says the Energy Plan does not restrict natural gas generation. “Moreover, CPFL’s allegations with respect to the state Energy Plan involve only legal and policy matters and fail to raise any contested issues of material fact for which a hearing would be required,” the filing said.
Built in 1953, the plant is located on Seneca Lake in Yates County. It was purchased in 1998 by AES and operated by it and its subsidiaries until March 2011, when it was mothballed. The plant has not operated since.
During the AES bankruptcy proceeding in 2012, the company said it intended to permanently retire the plant. The plant was sold to GMMM Holdings, which in turn sold the facility to Greenidge in February 2014, according to the Greenidge filing.
Greenidge said most permits are current, but it needs an air permit and water withdrawal permit from the state Department of Environmental Conservation.
HOLLYWOOD, Fla. — New carbon emission regulations may face an uncertain future in the courts, but investors and utility executives said last week it won’t upset the long-term shift away from coal-fired generation and toward increased efficiency.
Twenty-six states have joined legal challenges to the Environmental Protection Agency’s Clean Power Plan.
“I don’t think it matters [to utility capital spending plans],” said Stuart Zimmer, general partner with Zimmer Partners, which manages energy-focused hedge funds. “You have to comply. You don’t know if you’re going to win or lose [in court]. You have to have a plan in place,” he said during a panel discussion at the Edison Electric Institute’s 50th annual Financial Conference.
James Hempstead, associate managing director for Moody’s Investors Service, agreed.
With the legal challenges, “there will be some starts and stops and some lurching over the next couple of years … but utilities can see the writing on the wall. They know that they need to shift their generation supply mix and it needs to be a cleaner mix and they need to be more efficient … and that’s where they’re heading.
“To the extent that you have the CPP that is a federal mandate that helps you get your state regulators to get those costs approved, that’s a good thing,” he added. “Whether its MATS [Mercury and Air Toxics Standards] or CSAPR [Cross-State Air Pollution Rule] or CAIR [Clean Air Interstate Rule] or the CPP or whatever the next version of that is going to be, [the regulations are] going to keep coming. That is what’s incorporated into our long-term view.”
Akins
American Electric Power CEO Nick Akins said his company has urged officials in the 11 states in which it operates to file implementation plans even as nine of them fight the rule in court.
“Clearly [it’s] a great investment opportunity for AEP moving forward,” he said, referring to grid upgrades to support renewables and distributed generation. “I don’t think there’s any question that customers in the future are focused on a cleaner energy economy.”
Moody’s Toby Shea agreed that the CPP is an opportunity for utilities to increase their rate bases. “In the near term we see it as more positive than negative,” he said, adding, “There’s a risk that you keep making all these investments and pushing up the rates — at some point you’re going to get some pushback” from regulators.
Overruns, Waste Issue Cloud Nuclear’s Future
Although the CPP encourages emissions trading — which would benefit non-emitting generation — few utilities are likely to include nuclear plants in their capital spending plans, speakers said.
Adams
“It seems to me that the only place we are going to see nuclear generation construction is going to be in fully regulated, vertically integrated utility states like you’re seeing in South Carolina and Georgia,” said Kenneth Adams, managing director of global public markets for TIAA-CREF, which manages retirement and other investment funds.
Zimmer said nuclear power will be a tough sell even to utilities in such states because of the cost overruns plaguing Southern Co.’s two new Vogtle units in Georgia, which are more than three years behind schedule, and SCANA’s two new Summer units in South Carolina, now projected to cost more than $12 billion, a 20% increase over the original price tag.
“Southern Co. has seen what was once the best premium in the group get destroyed by the risk and overhang of building a nuclear plant and cost overruns. It now trades at a much lower price relative to its history,” he said. “SCANA … has seen its stock trade at a 10 to 15% discount. [Nuclear plants] are really risky investments. You don’t have real clarity on what they’re going to cost.”
Zimmer
Zimmer said he had discussed with Dominion Resources CEO Thomas Farrell and CFO Mark McGettrick the possibility of adding a third unit to their North Anna nuclear complex. “[They said] ‘it’s our second-to-last option.’”
Policymakers will have to make “a big-boy decision” about nuclear waste to improve nuclear power’s prospects, said Michael E. Webber, deputy director of the Energy Institute at the University of Texas at Austin.
“Either we store it or we process it,” he said. “I’d like to see us process it because that is the better environmental solution and the better economic solution.”
PJM on Friday asked FERC to authorize cost responsibilities for $687 million in upgrades included in a revised Regional Transmission Expansion Plan approved by the Board of Managers in October (ER16-319).
Click to zoom.
The cost allocations would become effective Feb. 11. Transmission customers have 30 days to submit comments about the proposed charges.
The upgrades address reliability issues or economic constraints, all on lower voltage facilities.
Included are 11 market efficiency projects, estimated at $59.3 million, which are expected to produce savings of $815 million over 15 years. They were selected from among 93 proposals, 58 from nonincumbent transmission developers.
New baseline reliability projects totaled $580.5 million. An additional $47.7 million was authorized for changes to previously approved baseline projects.
New York officials and others last week asked FERC to rehear an order that exempted renewable generation and self-supply resources from buyer-side mitigation rules in the state’s installed capacity market (EL15-64).
But several parties who sought the exemption in May say the commission’s order will stifle development of the very resources it is trying to protect. Petitioners representing power generators, meanwhile, sought to reverse or limit the exemptions.
“The commission adopted a renewable generation exemption that is unduly restrictive because it is limited to a narrowly defined population of intermittent renewable resources, and further constrains the exemption with an annual cap on new eligible renewable capacity,” said the original petitioners, the New York Public Service Commission, the New York Power Authority and the New York State Energy Research and Development Authority. “Moreover, the commission declined to adopt a general exemption for demand response resources.”
The petitioners were joined by New York City, the Natural Resources Defense Council and intervenors representing large commercial and industrial customers.
The order stated that a renewables cap should be developed through a stakeholder process at NYISO. The petitioners say they want no cap imposed. They also objected to the exclusion of demand response resources.
In other filings:
Astoria Generating, TC Ravenswood, NRG Energy and Cogen Technologies Linden Venture want to eliminate the self-supply exemption, saying that FERC did not identify evidence that it would not suppress capacity market prices.
The Independent Power Producers of New York and the Electric Power Supply Association asked the commission to bar state entities such as NYPA from using the self-supply exemption, saying they have ”demonstrated a strong incentive and ability to subsidize new entry to suppress ICAP prices.”
Transmission owners Consolidated Edison, Central Hudson Gas & Electric, Rochester Gas & Electric and New York State Electric and Gas requested a rehearing because there was no inclusion of demand response resources.
Entergy is advocating a reversal of the order, saying the exemptions will “become tools to artificially suppress capacity prices.”
HOLLYWOOD, Fla. — FirstEnergy and American Electric Power, both awaiting rulings from Ohio regulators on their requests for subsidies of their generation plants, may take different paths if they are unsuccessful.
The companies’ chief executives told analysts and investors at the Edison Electric Institute Financial Conference last week that they expect the Public Utilities Commission of Ohio to rule on their requests for above-market power purchase agreements with their generators late this year or early in 2016.
Akins
CEO Nick Akins indicated the company would like to rid itself of its Ohio merchant fleet, which the company acknowledged in January it had put on the block. “We’re going to be a regulated utility. That’s what we’re good at,” he said, saying that investments in generation are riskier than those in transmission and distribution.
Akins said AEP and FirstEnergy are “on the same page” regarding the need for regulators’ help to improve the finances of their Ohio fleets.
But FirstEnergy CEO Chuck Jones said his company has no plans to sell or spin off its Ohio generation fleet.
Jones
“I come from a bias that generation, transmission and distribution together is the best way to serve customers. I understand the pressures on competitive generation. I think we’ve taken steps to position ours to where we’re cash flow positive each year for the next several years — through 2018.
“I don’t see [current] prices being the right prices to sell these tremendous base load assets. So my view is we’re going to stabilize it. We’re going to keep it cash flow positive, keep it delivering positive earnings contributions.
“We’re going to work with our regulatory in Ohio to try to get 3,200 more megawatts into a safer environment for the foreseeable future … and long term we’ll see where it goes. Right now [a sale or spinoff] is not the focus.”
Chicken processor Allen Harim broke ground last week on a 1.57-MW solar installation. The 6-acre solar farm will supply about 11% of the energy used by its Harbeson processing facility.
The project, which will be connected with Delmarva Power & Light’s grid, will be owned and operated by Onyx Renewable Partners, which is owned by funds managed by Blackstone.
The installation is expected to produce 2.3 million kWh of power annually and reduce carbon emissions by 1,616 metric tons.
The Commerce Commission last week, by a 3-2 vote, approved Clean Line Energy Partners’ proposed Grain Belt Express, an HVDC transmission line that would pass through four Midwestern states.
The ICC put several conditions on its approval, including a prohibition on expanding capacity without commission approval, completion of financing and a requirement to get commission approval if any of the estimated $2 billion cost is to be borne by ratepayers.
The 780-mile line is designed to deliver Kansas wind energy into PJM. It has also received the approvals of regulators in Indiana and Kansas. Missouri regulators rejected it, but the company has vowed to reapply there.
Kevin Shepherd, a telecom industry veteran, has been named the new president and CEO of Manitoba Hydro. The Manitoba Hydro Electric Board recommended Shepherd for the position.
Shepherd rose through the ranks of MTS, the fourth-largest telecommunications company in Canada, and spent the last five years as president. He will assume the new position in December.
Baltimore Gas and Electric has applied for a rate hike for gas and electric customers to recover the cost of installing about 1.7 million smart meters. The Public Service Commission, which authorized the smart meter program in 2010, must approve the increase.
If approved, it would add about $15 per month to typical residential customers who receive both gas and electric service from the Exelon subsidiary.
“It is a very significant rate increase for our customers and our households that have combined gas and electric,” said Paula Carmody, head of the Office of the People’s Counsel. “They are asking for a profit level that’s much higher than we think is reasonable, that will likely be challenged.”
Denmark-based DONG Energy A/S is proposing a 1,000-MW offshore wind farm 15 miles south of Martha’s Vineyard, outlining its plans less than a year after the proposed Cape Wind project in Nantucket Sound suffered a stunning financial setback.
The Danish company said its Bay State Wind project would install up to 100 turbines off Cape Cod on a lease it recently acquired. DONG Energy has yet to file any applications for the projects with the federal or state government, and the transfer of the lease must be approved by the U.S. Bureau of Ocean Energy Management.
DONG Energy faces lengthy state and federal permitting processes that include environmental reviews and approvals for where its power lines would come ashore. It would take about three years to build the wind farm, and the first phase could include 30 to 35 turbines and be in service by early next decade.
State Rep. Garrett Bradley of Hingham filed a bill, which would convey the necessary easements to Tennessee Gas. Sandisfield-area lawmakers refused to file the bill because it would require the removal of protected land from the shelter of Article 97 of the state constitution, the state’s primary conservation law.
State Sen. Benjamin Downing said that the community opposes it, and passage could set a “dangerous” precedent of taking Article 97 lands to build fossil fuel energy infrastructure. He said the bill “flies in the face of the commonwealth’s energy priorities.”
Consumers Energy’s announcement that it will retire its coal-burning B.C. Cobb Plant in Muskegon brought cheers from environmentalists but could be trouble for the Port of Muskegon.
Coal deliveries accounted for about half of the tonnage coming into the port, and the volume of traffic is an important consideration if the port continues to be dredged. Without coal deliveries, the volume of cargo moved through the port will fall below the 1 million-ton annual threshold that the U.S. Army Corps of Engineers sets for “high-use” harbors, which are guaranteed to get dredged.
Muskegon city officials are setting up meetings with the corps to determine a way to keep the harbor’s dredging program active.
The Public Service Commission unanimously approved three solar projects on Nov. 10.
The plants, which will produce a combined 105 MW, will be located in Sumrall, Hattiesburg and Gulfport. They are projected to be in service for at least 25 years.
Hattiesburg Farm will cost $85 million and cover 450 acres; Mississippi Solar 2 will cost $102 million and require 4,085 acres in Sumrall; and CB Energy will spend $6.4 million on its farm at the U.S. Naval Construction Battalion Center in Gulfport.
Getting ‘Brownfield’ Solar Credits from an Apple Orchard? Nice Try
A state court upheld a decision by the Board of Public Utilities to deny brownfield development solar credits to a company that wanted to build on a former apple orchard.
Millenium Land Development said the orchard qualified as a brownfield because of past pesticide use. The BPU denied the request. The state Court of Appeals agreed, saying the land had been assessed as farmland, not a brownfield. The state’s Energy Master Plan discourages the use of open land and farms for solar development.
US Wind Inc. and RES America Developments were the high bidders to win lease rights to about 344,000 acres of ocean floor near Atlantic City to build wind farms.
US Wind bid a little more than $1 million for about 183,000 acres. RES offered $880,715 for 160,480 acres.
Together, the areas could support up to 3,400 MW of commercial wind generation, but it’s likely to take seven or eight years for operations to be developed.
State Supreme Court Denies Petition Against 4 PRC Members
The state Supreme Court last week rejected an environmental nonprofit group’s attempt to disqualify four of the five Public Regulation Commission members from voting on a high-profile case about a coal-fired power plant.
The nonprofit group New Energy Economy alleged commissioners Pat Lyons, Sandy Jones, Karen Montoya and Lynda Lovejoy have shown bias and pre-judgment in their public statements about Public Service Company of New Mexico’s plan to shut down two generating units at the San Juan Generating Station, a coal-fired power plant that PNM co-owns and operates.
State Dept. Refuses Certificate for Entergy’s Indian Point
The Department of State has refused to issue a certificate for the continued operation of Entergy’s Indian Point nuclear generating station, saying that the plant has been “damaging the coastal resources of the Hudson River” for decades by killing fish in its cooling system.
Secretary of State Cesar Perales rejected the coastal zone certificate for Indian Point, noting that the plant is close to two seismic faults and is too close to New York City. But Entergy said Perales’ rejection is moot, as it had withdrawn the application last year after a state appellate court ruled that it was not necessary. Entergy is seeking a 20-year license extension for the two reactors.
The secretary’s refusal is the latest blow against Indian Point. The state attorney general has been critical of the plant’s operation, and Gov. Andrew Cuomo has called for its closure.
Gov. Andrew Cuomo has killed a three-year-old proposal to build a liquefied natural gas terminal 19 miles off Jones Beach, citing concerns about the environment and terrorism.
The deep water Port Ambrose docking station was to supply the state with LNG from overseas. Cuomo, in formally announcing his veto, said al-Qaida has threatened to target such facilities and Superstorm Sandy was powerful enough to damage infrastructure built to survive 100-year storms. He also said the fuel port would harm commercial fishing and conflict with a major wind farm proposed for the same waters.
“When you put all of those things together, the reward was not worth the risk,” he said.
Invenergy’s proposed natural gas-fired power plant in Burrillville would lead to an even larger net decrease in regional emissions than initially forecast, the company said last week. The Chicago-based energy developer has argued that because its efficient combined-cycle plant would sell power at a lower price than competing generators, it would replace the output of older, less efficient facilities.
According to the company’s figures, the 900-MW Clear River Energy Center would reduce carbon dioxide emissions across New England 9% if it were to go online immediately. If the project starts generating power in 2019 as scheduled, the effect would be less dramatic because some of the biggest emitters, such as Somerset’s coal-fired Brayton Point Power Station, would already be closed, but the overall decrease would still be about 1%.
In a filing made with the Energy Facility Siting Board, Invenergy claims the decrease could actually be larger because of the recently announced closing of the Pilgrim Nuclear Power Station in Massachusetts.
The Public Utilities Commission has approved a 103-MW wind facility to be built near Newell. Developer Wind Quarry says the 45-turbine Willow Creek Wind Farm should be on line by December 2017.
The state ranks fourth in the nation in potential wind energy, and the Willow Creek facility would bring the state’s wind capacity to 987 MW. “Many people will be surprised to know that the addition of the Willow Creek project is likely to propel South Dakota to be the state with the greatest amount of wind as a percentage of the state’s total capacity, in the nation,” Commissioner Gary Hanson said.
Wind generation from the plains hit several all-time highs this fall, according to ERCOT and the federal Energy Information Administration. An instantaneous peak of 11,467 MW was set Sept. 13, which was broken on Oct. 21 with a new record of 11,950 MW. That record was eclipsed on Oct. 22 at 12,238 MW.
ERCOT and EIA attributed the new records to increased capacity, strong winds and increased demand due to warm autumn weather. The records were set despite lower capacity factors, estimated at between 75% and 81% during the fall compared to 83% in February.
The government predicts that with new capacity coming online, the latest record is likely to fall soon.
The excess of wind generation in the state is prompting some utilities to offer plans that don’t charge for electricity during off-peak hours, if customers agree to pay a premium during higher demand times. The New York Times recently profiled several customers who are taking advantage of a TXU Energy program that offers free overnight electricity in exchange for higher peak pricing. It said about 50 retail electricity customers are offering similar plans in the state.
Some customers said they wait to run energy-intensive appliances until after 9 p.m., when the power supply is gratis. Most wind generators in the state produce more electricity during the nighttime, when the wind blows more strongly. Wind power now represents about 10% of the state’s overall generation.
“Any plan that creates an incentive for a customer to shift a load off peak [hours] is helpful to grid operations. It’s a better use of the system,” said Paul Wattles, ERCOT senior market design analyst, told the Midland Reporter-Telegram.
Houston Signs 20-Year, $80M Solar Deal with Hecate Energy
Houston will ramp up its use of green energy to keep the lights on and laptops humming at City Hall with the approval last week of a 20-year, $80 million deal to purchase solar power from Nashville-based Hecate Energy.
Hecate, which operates 20 plants around the world, will supply the city with up to 30 MW of solar-generated power annually, beginning in December 2016, from a plant it plans to build near Alpine. Hecate offered a two-decade fixed price of 4.8 cents/kWh, nearly 2 cents less than the city pays under its current contract.
The contract will provide about 7% of the city’s annual electricity needs and will replace electricity that now is purchased from coal-fired generators.
Ector County 350-MW Gas Plant Begins Formal Operations
The Ector County Energy Center, a 350-MW natural gas plant, was formally opened earlier this month, heralded by local governmental officials as a boon to the local tax base.
The plant is designed to provide peaking energy and respond quickly when ERCOT requests additional power supply. It uses two GE 7FA simple-cycle combustion turbines fueled by Permian Basin natural gas.
Commercial operation began in September. Generation from the plant has already hit about 294 MW.
Dominion Virginia Power has requested permission to construct a 230-kV transmission line that would run above ground for 5 miles along Interstate 66 in Prince William County.
Some county officials and residents had pushed for at least part of the line to be buried.
The State Corporation Commission is expected to make a decision within 18 months.
