FERC on Friday accepted SPP’s request to waive Tariff provisions governing the selection of an industry expert panel, allowing it to use one of its 2016 panelists to complete the 2015 panel evaluating proposals for the RTO’s first competitive solicitation under Order 1000 (ER16-126).
SPP filed the waiver request with FERC on Oct. 20, saying that the only candidate in its 2015 pool with expertise in one of five subject areas required wouldn’t be able to serve. (See SPP Seeks Waiver on Panel; Sets New Wind Records.)
FERC found “good cause” to grant SPP’s requested waiver, saying it “will remedy a concrete problem and allow for regulatory certainty regarding review of the proposals submitted for the project.”
FERC noted the waiver requested was of limited scope, covering just two subsections of SPP’s Tariff and it addressed a one-time event. The commission said the request “will create no undesirable consequences since the candidate’s qualifications will be reviewed and approved by both the Oversight Committee and the SPP Board of Directors prior to serving on the IEP.”
MISO’s Planning Advisory Committee continued discussion Wednesday on a revised planning futures process that will help the RTO develop transmission needed to comply with the Clean Power Plan.
Durgesh Manjure, MISO’s manager of resource adequacy coordination, said the final CPP plan will be incorporated into the MISO Transmission Expansion Plan beginning with the 2017 cycle. The MTEP 16 futures are based on the draft rule, which was changed significantly.
“Futures for the next few MTEP cycles are expected be driven largely by the CPP. Work done for MTEP 17 should allow for more efficient development of MTEP 18-plus futures,” MISO wrote in a presentation.
MISO “believe[s] it’s appropriate to bring in the Clean Power Plan to the MTEP 17 cycle,” even though implementation itself isn’t slated to begin until 2022, Manjure said. States are required to submit a compliance plan or an extension request in September 2016 with final plans due in September 2018.
While MISO said incorporating the CPP final rule into MTEP16 “could be beneficial,” there are ultimately no plans to revise MTEP16 futures to reflect the final rule.
Stakeholders have said that drivers used for MTEP futures should not be limited by existing policies and include policies on the horizon. They also asked that MISO share historical and forecast data on key variables before workshops take place.
Transmission-owning stakeholders requested that MISO review its resource siting process. The RTO said siting is to be reviewed in the coming year.
“It’s a journey of discovery,” Manjure said, quoting MISO executive vice president of transmission and technology Clair Moeller’s stance on CPP preparation. “By no means are we jumping the gun on MTEP 17. This is a precursor to the conversation,” he added.
Under the realigned MTEP futures development, MISO will share relevant historical and forecast data at the beginning of an MTEP cycle, then check if the existing futures sufficiently capture the economic and policy landscape for long-term transmission planning, reusing them if appropriate. The RTO will also actively look for any new sensitivity scenarios and plan to reuse resource expansion and siting in successive PROMOD models. PROMOD models themselves will be updated annually to represent the latest topology in MISO’s footprint.
“The timeline and overall process definitely warrants a look,” Manjure summed up.
Manjure said the revised planning futures process will be subject to “ongoing discussions” at upcoming PAC meetings; no voting date has been set.
Proposed Changes to Expedited Project Review Fall Short, Stakeholders Say
The PAC continued its review of MISO’s proposed changes to the out-of-cycle review process, with some stakeholders complaining that the changes don’t address their concerns that expedited projects could undercut competition under FERC Order 1000.
The RTO is drafting changes to its business practices in response to the uproar earlier this year over Entergy’s $200 million out-of-cycle project in Louisiana.
MISO defended its proposal to eliminate detailed criteria defining expedited projects, saying it did so because the RTO does not have the authority to challenge load-serving entities’ load assumptions or regulatory drivers. MISO said it would consider adding more detailed criteria “provided that those bounds do not require MISO to challenge the obligations of the LSE or [transmission owner].”
“We really believe that the best mechanism to address these types of issues is transparency,” said Matthew Tackett, a MISO principal advisor.
MISO also said the PAC does not have the authority to order planning staff to report to MISO’s Board of Directors on expedited projects. MISO staff reports to the board at its own discretion.
“Of course we will consider [recommending] these projects if there’s an appropriate need and if the timing is appropriate,” Tackett said.
Stakeholders argued that under the proposed changes, MISO and the PAC can do little to prevent TOs and LSEs from inflating their load demands and proposing an expedited project under false pretenses. One PAC member said it would be “troubling” if MISO chooses to interpret the Tariff language narrowly and ignore stakeholder concerns.
Another said the revision process had become “a very frustrating exercise” because redline suggestions to the manual language have not been accepted by MISO.
Discussion on the process will wrap up at December’s PAC meeting, when the committee will be asked to approve the changes.
Queue Remodel Moves to Final PAC Review; Stakeholders Request Transition Plan
MISO expects to draft final Tariff language for its interconnection queue reform effort in the coming month.
The proposed changes, which include the introduction of phases and related fees along with a reduction of restudies, drew criticism from stakeholders at last week’s PAC meeting. Stakeholders representing wind power developers were particularly critical of the plan, saying it could increase their costs to $25,000/MW for projects that may not come to fruition.
The last revision of queue rules was completed in 2012.
“We have made changes over the past, but they’re not going as well as we envisioned, so this is our chance to go back and fix it,” Vikram Godbole, senior manager of MISO’s generator interconnection planning group, told the committee.
Under current rules, Godbole said, customers may leave their interconnection projects in the existing queue even if they don’t wish to proceed. He also said the current queue process takes too much time and doesn’t lend enough certainty to interconnection customers due to the volume of restudies.
“What we’re going to do is restructure the restudies and minimize the number of restudies allowed,” he said.
The new rules would eliminate restudies after interconnection customers execute a permanent generator interconnection agreement.
The new rules set new deadlines for receiving refunds of milestone payments.
Godbole said interconnection customers proposing a project will receive a detailed study from MISO in the first 110 days of the process. After reviewing the study, the requesting owner can decide whether to seek a refund of the $5,000/MW milestone paid at the queue application. Before executing a generator interconnection agreement, customers must pay two more milestones during phases that last 80 and 135 days, respectively.
No refunds will be permitted for interconnection customers that do not withdraw their projects before the third, 135-day phase begins.
Godbole encouraged stakeholders to view the proposed milestone payments as “deposits.”
Several stakeholders asked for more time to consider the changes, saying at just four months the process felt “rushed.” Godbole responded that MISO has incorporated three cycles of comments thus far on the proposed changes.
Some stakeholders requested a clearer transition to the new rules.
“We’ve heard it crystal clear that stakeholders want a transition plan by the time we file with FERC,” Godbole said. He asked stakeholders to provide “actionable items” that MISO can incorporate into the plan.
MISO asked for PAC’s feedback on the changes by Nov. 25 in order to present final Tariff language to the committee on Dec. 16.
PJM expects 177,628 MW of generation this winter, a 35% margin over the projected peak demand of 131,720 MW, the RTO said Thursday.
The peak load for the 2014-15 season was a record 143,295 MW, set in February. Temperatures are forecasted to be milder this year.
Generator outage rates, which exceeded 20% in 2014, were generally less than 15% in 2015.
While last winter saw colder temperatures than the previous year, when the region was hit by a polar vortex, the RTO experienced fewer generator outages — rarely exceeding a 15% outage rate compared with rates as high as 22% in January 2014.
“PJM has taken many steps to reinforce generator readiness and to continue to improve coordination with natural gas pipelines, a key source for a large portion of the generation fleet,” said Michael Kormos, executive vice president and chief operations officer for PJM.
In preparing for the winter, PJM offered testing to generating units that had not run in the eight weeks prior to Nov. 1, repeating a program begun last year, and had generators complete a survey assessing their fuel supplies.
About 10,000 MW of generation have retired since last winter, only about 3,000 MW of which has been replaced, Kormos told FERC in September. (See PJM to FERC: We’re Prepared for Winter.)
PJM should tighten rules on demand response and market power, the Independent Market Monitor said in its third-quarter State of the Market Report.
The report, which included eight new recommendations, concluded that the RTO’s energy, capacity and regulation markets were competitive for the first nine months of the year.
“The markets are working pretty well,” Monitor Joe Bowring said in an interview. But, he said, “there is still progress to be made in some of the details of the capacity market rules, and we’re concerned about some of the proposed changes to market rules, particularly the hourly offer flexibility.”
The study, released Thursday, found that energy market prices dropped by one-third compared with the same period last year, due to lower fuel prices and decreased demand. The load-weighted average real-time locational marginal price was $38.94/MWh compared with $58.60/MWh in 2014.
Uplift decreased 68% in the first nine months over a year ago, from $899.1 million to $285.7 million, but Bowring said the charges remain high, in large part because of inflexible unit parameters based on rigid gas supply arrangements.
The report said that the Capacity Performance rules will address those problems in the future.
“Outages were high, performance incentives remain weak and there is no resolution of the disconnect between the incentives facing electric generating units and the incentives facing gas pipelines, which is a barrier to the construction of new pipeline capacity,” the Monitor said.
Bowring noted his particular concern over the ability of generators to place hourly instead of daily offers.
“The PJM market design incorporates a variety of rules designed to help ensure competitive outcomes,” the report said. “When basic elements of those rules are modified, e.g. the raising of the overall $1,000/MWh offer cap and the introduction of hourly offers in place of daily offers, it is essential that effective market power mitigation be maintained.
“A direct and effective substitute for the current market power mitigation rule limiting units to one offer per day would be to limit any hourly offer changes during the day to changes in the cost of fuel. The failure to maintain limits on aggregate market power will lead to the exercise of market power and the associated negative impacts on the competitiveness of PJM markets.”
The report also found that net revenue for new entrants was down for the first nine months, decreasing 13% for a combustion turbine, 18% for a combined-cycle, 53% for a nuclear plant, 20% for wind and 5% for solar.
Congestion charges dropped by 33% from $1.7 million for the first nine months of 2014 to $1.1 million this year.
The report included eight new recommendations, three listed as high priority. One concerns the energy market and two address demand response, provided that DR remains in the wholesale market following the Supreme Court’s ruling in the Electric Power Supply Association challenge. (See FERC Jurisdiction over DR in Peril as Supreme Court Splits.)
The rules around the three pivotal supplier test should be clarified and documented. In addition, markup should be constant across price and cost offers; there should be at least one cost-based offer using the same fuel as the available price-based offer; and the parameters of the cost-based offer should be at least as flexible as the parameters of the available price-based offer.
PJM should require nodal dispatch of demand resources with no advance notice required. Alternately, if nodal location is not required, subzonal dispatch of DR with no advance notice should be mandatory.
PJM should eliminate the measurement of DR compliance across zones within a compliance aggregation area. “The multiple zone approach is less locational than the zonal and subzonal approach and creates larger mismatches between the locational need for the resources and the actual response.”
The remaining recommendations were of medium and low priority and regarded uplift and planning, respectively.
PJM spokesman Ray Dotter had no specific comment on the recommendations, saying only that many “appear consistent with the themes of prior State of the Market reports.”
“PJM looks forward to working with the Independent Market Monitor to flesh out these new recommendations to ensure a complete understanding and to determine how they may be addressed, including through potential introduction into the stakeholder process,” he said.
The development of carbon capture and storage technology will be vital to address climate concerns, but it will require government support to make it happen, according to a report by the National Coal Council.
The report was drawn up at the request of Energy Secretary Ernest Moniz, who wanted recommendations on what can be done to encourage development and use of carbon-capture technology and how to level the playing field.
The council’s report said the Clean Power Plan rules have “severely tilted the energy playing field,” and that the incentives available for carbon capture and storage are too small to encourage commercial use. “Without commercial-scale deployment, developers have no history to understand technical risks, frequency and duration of down time, and other critical factors that become known only with operation,” the report said.
The Department of Agriculture is providing nearly $2.3 billion in low-interest loans to rural electric cooperatives for infrastructure improvements.
The loans, provided through the Rural Utilities Service Electric Loan Program, will go to 77 cooperatives and smaller utilities in 31 states. USDA said the loans will help build or improve about 12,000 miles of transmission and distribution lines. They will also finance $108 million for smart grid technology improvements, $41 million for renewable energy programs and $9 million for storm damage restoration.
A U.S. District Court judge ruled that Environmental Protection Agency Administrator Gina McCarthy must testify in a case pitting Murray Energy against the agency’s Clean Air Act regulations.
The coal producer’s attorneys argued that McCarthy was deeply involved in drafting the regulations, and Murray should be able to depose her about her analyses concerning possible loss of jobs caused by the regulations. EPA and the White House sought to block her appearance, saying the regulations are clear enough on their own and that McCarthy’s testimony is unnecessary.
Judge John Preston Baily of the District Court for the Northern District of West Virginia ruled that McCarthy’s testimony is material. “By statute, the administrator is responsible for conducting the evaluations in question,” Bailey wrote in his order, adding that “she has personally been involved with discussions about” the regulations.
FERC Sets Tech Conference for ‘Connected Entities’ Rule
FERC has agreed to set up a technical conference to explore its proposed rule that would require ways to identify companies and individuals participating in wholesale energy market trades.
Several parties asked FERC for clarity about its Notice of Proposed Rulemaking issued in September that would require RTOs and ISOs to begin registering market participants through common alpha-numeric identifiers, including lists of their “connected entities” and a description of their relationships (RM15-23). The proposal would use a new system called Legal Entity Identifiers, which are already used by the Commodity Futures Trading Commission and Securities and Exchange Commission to track swaps trades. (See Are You Two Related? FERC Wants to Know.)
Several parties asked for either an extension of the Dec. 8 deadline for comments on the notice or a technical conference to clear up what they called “ambiguities.” FERC scheduled the conference for Dec. 8 and extended the comments deadline to Jan. 22.
Solar energy advocates and some legislators are warning that the upcoming reduction in the Investment Tax Credit for solar will impact customers and small businesses in the Midwest, where few state-level solar programs are in place to provide incentives in addition to the federal subsidies.
Ray Davis, president of OGW Energy Resources, an Ohio-based solar developer, said it is difficult for solar to compete without the subsidies. “As we are primarily a coal region, our grid kilowatt-hour costs are relatively low as compared to other regions,” he said. “Therefore the ITC truly is the part of the puzzle that makes solar fiscally feasible in the Midwest.”
Legislation extending the credit for wind and other renewables only — but not solar — was passed by the Senate Finance Committee earlier this year. Without an extension, the commercial tax break will decrease from 30% to 10% at the end of 2016, and residential support will be eliminated.
Despite the retirement of 23 GW of coal-burning capacity this year, American power plants will burn the same amount of coal next year. Surviving coal plants will ramp up to meet demand and burn about 773 million tons of coal in 2016, according to the Energy Information Administration.
In addition to increasing generation to fill the void left by plant closures, coal is also expected to compete strongly next year as natural gas steadily becomes more expensive, EIA said. Coal prices are expected to remain fairly steady.
“You’ve got this big wave of retirements that you don’t get for the rest of the decade,” said James Stevenson, director of North American Coal at IHS Inc. in Houston. “That means after this, coal demand is pretty stable.”
Obama’s Keystone Decision Elicits Yawn from 35% of US
Although the Keystone XL issue has dominated the news media, only about a third of Americans care one way or the other about President Obama’s rejection of the pipeline that would have delivered heavy crude oil from Canada to the Gulf Coast, according to a Reuters poll.
About 35% of 920 people polled said they didn’t agree or disagree with the president’s decision. Another 27% qualified their opinions with “somewhat.” Obama rejected the proposed 1,200-mile pipeline on Nov. 6.
Wellinghoff: Pipeline Purchases May not be Wise for Utilities
John Wellinghoff
While Eversource Energy, Duke Energy and Dominion Resources are betting big on natural gas pipelines, the volatility of the gas market in light of growing renewable and battery market power could leave those investments stranded, according to former FERC Chairman Jon Wellinghoff.
Wellinghoff told Bloomberg Business that spending billions on natural gas pipelines may look like good sense when coal plants are closing and natural gas-fired plants are sprouting. But he noted that renewable energy is growing, and battery storage technology is emerging quickly.
“These utilities are taking a risk that these will be stranded assets that ultimately their shareholders will have to pay off,” Wellinghoff said. “We will see regulators being more critical of these asset decisions as prices of renewables continue to go down.”
Report: EVs Emit less Pollution over Life Cycle and Getting Cleaner
Electric vehicles generate half the emissions of gasoline-powered cars over their lifetimes, even when pollution from battery manufacturing is accounted for, according to a new study by the Union of Concerned Scientists.
The study looked at the greenhouse emissions of conventional and electric vehicles during manufacturing, operation and end of life.
While electric cars generally exceed the global warming emissions of gasoline cars in production because of their use of large lithium-ion batteries, they make up for that within 18 months of driving, according to the report.
A series of unplanned shutdowns at the Tennessee Valley Authority’s Sequoyah Nuclear Power Plant near Chattanooga has spurred the Nuclear Regulatory Commission to increase its oversight of the plant.
NRC cited four outages at the plant’s Unit 1 in the past three quarters. “Overall, the Sequoyah plant is operating safely,” the commission said. “However, these shutdowns point to potential performance issues and we want to ensure that TVA addresses them appropriately.”
TVA spokesman Jim Hopson said the utility has taken steps to improve operations. “We’ve already placed initial corrective actions into place to improve overall performance,” he said. “We’ll continue to look at that. We’ll focus on trying to get Unit 1 back into regular oversight status.”
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.
