FERC has charged a Pennsylvania-based power trading company with manipulating the PJM wholesale market by making risk-free up-to-congestion trades in the summer of 2010.
The Notice of Alleged Violation said Coaltrain Energy of Landenberg, Pa., executed up-to-congestion transactions “that were designed to falsely appear to be spread trades but that were in fact a vehicle to collect” line-loss payments from PJM. It said the company “sought not to profit from changes in price spreads but rather to profit by clearing large volumes of up-to-congestion transactions.”
Coaltrain is the third company FERC has charged recently with such trading violations, following actions against Powhatan Energy Fund of Pennsylvania and Florida-based City Power Marketing last year.
The notice named principal owners Peter Jones and Shawn Sheehan, along with traders Jeff Miller, Robert Jones, Jack Wells and Adam Hughes.
According to their LinkedIn profiles, and PJM and FERC records, Sheehan and Hughes are currently affiliated with XO Energy, a PJM member, and formerly worked at Energy Endeavors, another company that PJM has accused of manipulative UTC trades. XO and Energy Endeavors have listed the same Landenberg address as Coaltrain.
Jones also was affiliated with Energy Endeavors.
PJM sued Energy Endeavors in Delaware Superior Court seeking the return of more than $6 million in line-loss profits. The same complaint sought $17 million from City Power Marketing. The docket lists no filings since 2013, when the court denied the defendants’ request to stay the proceedings. PJM’s most recent financial statement indicates it is still attempting to collect the money — among a total of $28 million in defaults resulting from line-loss payments later questioned by FERC.
Energy Endeavors asked FERC in 2011 to cancel its market-based rate authority, saying it had ceased trading activities.
Sheehan did not immediately return a call for comment.
MISO officials are considering changes to how they conduct the annual Transmission Expansion Plan in order to focus future plans on long-term needs.
Officials told the Planning Advisory Committee meeting last week that they are considering changes to the first two steps of the seven-step futures development process.
“Year after year, the annual MTEP future definitions have modeled similar themes,” MISO said. From MTEP 12 through MTEP 16, the RTO has modeled low-growth, high-growth and business-as-usual cases.
Under the proposed change, planners would refresh the uncertainty variables annually based on whether there are new drivers for revising futures definitions.
Beginning with MTEP17, planners would use futures for as many as three years. MISO said sensitivities to existing futures can capture specific system needs without having to design new futures. For example, rate-based and mass-based compliance approaches can be studied as sensitivities to the Clean Power Plan future.
“After evaluating near-term needs for the last several MTEP cycles, it’s time to focus on long-term overlay design and development,” MISO said.
Stakeholders will discuss the proposed changes at the October and November PAC meetings. MISO hopes to finalize a revised process by end of the year.
MISO Proposing Changes to Review of Out-of-Cycle Projects
MISO has proposed changes to the way it handles the review of expedited projects to quell complaints over Entergy’s Lake Charles out-of-cycle transmission upgrades.
“We do think a few minor adjustments are necessary,” said MISO’s Matt Tackett, who presented the proposed changes.
Entergy’s $187 million out-of-cycle transmission project to serve additional load in the Lake Charles, La., industrial zone created a row that lasted for months. (See Entergy Out-of-Cycle Requests Win MISO Board OK.)
MISO is proposing that projects meeting the voltage and cost thresholds for classification as market efficiency projects be tested to see if they would have satisfied the 1.25 benefit-cost ratio. MISO’s presentation says this requirement would be for “transparency and informational purposes.”
The project would be reviewed by Sub-regional Planning Meetings (SPM) and/or the Technical Study Task Force (TSTF), where the submitting transmission owner would explain the need for the expedited review.
MISO planners will propose the project, or any alternative, for the MTEP, based on the project review and input from the SPM/TSTF.
The PAC would weigh in only at the end of the MTEP cycle.
Projects not eligible for expedited review would be any that are qualified as MEPs and are not required to meet transmission owner obligations. “It is expected that under normal circumstances, the transmission owners will identify the needs for projects early enough to be vetted in the normal MTEP process without the need for expedited review,” MISO said.
MISO will be accepting comments on the proposal until Oct. 16. After reviewing the comments, MISO will bring any revisions to the November PAC for the final proposal.
One of the most vocal critics of MISO’s handling of Entergy’s Lake Charles project, George Dawe of Duke-American Transmission Co., said the proposed changes are not an improvement.
“I’m more concerned now than I was with the original [Business Practices Manual] language,” said Dawe, who represents the Transmission Developer Sector at the PAC. “It seems to me you’ve gutted the BPM.”
Dawe said the current BPM allows the PAC sectors to register their displeasure with a proposed out-of-cycle project to the MISO board.
“It seems to us that a controversial expedited project should be required to pass more stringent review, not less review and no PAC vote,” he continued after the meeting. “Under the new process, the board would not be aware of [PAC stakeholder] displeasure until the end of the year when comments on the MTEP are solicited. By that time, the project would already have been de facto approved and potentially under development by the transmission owner.”
Former Wisconsin Public Service Commissioner Eric Callisto, now a partner with law firm Michael Best & Friedrich, also criticized the proposal, saying “I think the whole tone has changed in many ways.”
“As proposed [the changes] don’t strike the right balance between truly urgent needs that justify MISO’s expedited review versus the vast majority of projects that should make their way through the standard MTEP process,” he said afterward. “The proposal leans too much in favor of expedited review, to the detriment of an open and competitive process.”
MISO Seeks Feedback on Proposed Analysis of Final Carbon Rule
MISO is soliciting stakeholder feedback until Oct. 7 on a proposed framework for its study of the Environmental Protection Agency’s final Clean Power Plan.
The emissions targets will be examined under regional, sub-regional and state-level compliance, based on both rate- and mass-based caps. Planners also will consider a possible “equivalency exchange” rate between rate- and mass-based plans, given the possibility for disparity in state approaches.
Transmission needs will be identified and solutions developed for three futures. One assumes the CO2 limits are met. The “accelerated” CPP future assumes the targets are surpassed as technological advancements and public policy makes renewables and demand-side resources more competitive than expected. The “partial” CPP future assumes legal challenges slow or end compliance, and only the early, 2022 emission targets are met.
In November, MISO will finalize the scope of the study, including futures definitions and modeling assumptions.
Through mid-2016, planners will model futures and sensitivities, considering state implementation plans as they become available.
Planners will develop transmission overlays beginning in 2016. MTEP 2016, however, will be based on the preliminary EPA draft rule.
No Go for MISO-SPP Interregional Projects
MISO will not recommend approval of three potential interregional projects with SPP following an additional analysis that incorporated stakeholder feedback, Arash Ghodsian, MISO’s technical adviser for economic studies, told PAC members. MISO said it worked with stakeholders and SPP to “sharpen [its] analysis” and concluded that none of the three projects were justified by the projected benefits. Last month, MISO told the PAC two of the three projects looked less attractive following additional modeling, indicating a “disconnect in coordination” between the two RTOs. (See 2 of 3 MISO-SPP Seams Projects Likely Doomed.)
Ghodsian said MISO updated its regional congestion analysis after making some modeling changes and incorporating four futures. Staff identified future load changes between interregional and regional models and replicated SPP’s assumptions on retirements resulting from the Environmental Protection Agency’s Mercury and Air Toxics Standards.
“Given where we are with the projects, we don’t see why we need to go forward with any of them,” Ghodsian said. He said the projects are not more cost-effective at addressing the identified transmission issues than what MISO’s regional transmission plans build. Staff said its goal is not to find interregional projects for the sake of doing one, but to identify more cost-effective projects that would not be found in traditional regional planning. Ghodsian said MISO and SPP “effectively collaborated” during the study, gaining insight into their respective planning processes.
MISO’s revised analysis concluded:
The $141 million Elm Creek-NSUB 345-kV project showed present value benefits over 20 years of $25.6 million and a benefit-cost ratio of 0.49.
The $18.5 million rebuild of the S. Shreveport-Wallace Lake 138-kV line showed a benefit-cost ratio of 0.86.
The $5.3 million series reactor on the Alto-Swartz 115-kV line shows $20.5 million in benefits and a B/C ratio of 4.34, including the adjusted production cost benefit for MISO South.
MISO is evaluating alternatives to the Alto series reactor project in the market congestion planning study.
AEP Agrees to Pay Share of Market Efficiency Project
MISO’s Digaunto Chatterjee shared a letter from American Electric Power affirming its commitment to “pick up incremental cost/payment” if MISO approves either the Rockport-Coleman 345-kV double circuit or the Duff-Rockport-Coleman 345-kV single circuit market efficiency projects.
Staff have completed their economic and reliability evaluations. The reliability no-harm study identified constraints on two circuits for all three project alternatives, with an estimated mitigation cost of $200,000.
Staff said it will make its final recommendation during a special PAC meeting Sept. 25 but is still awaiting PJM’s final position and funding commitment.
The alternatives range in cost from $67.2 million to $152.5 million. PJM’s share of the alternatives could run as high as $85.2 million for Duff–Rockport–Coleman and $54.6 million for Rockport-Coleman, according to MISO staff.
MISO cited “Tariff challenges” to the Rockport-Coleman project, saying it is unclear how to bid out a double circuit line when a portion of the line is built for another RTO and not cost shared through the MISO Tariff. Tariff changes may be necessary to allow PJM to compensate MISO.
MISO is also studying two efficiency projects in the South with a total estimated cost of about $124 million that cleared the 1.25 B/C ratio: reconductoring the 115-kV Mabelvale-Bryant-Bryan South line near Little Rock, Ark., and building a 230-kV line from a substation to Lewis Creek in southeast Texas. Staff is continuing to gather information and stakeholder feedback on its analyses.
Second Round of Feedback on MTEP 15
MISO’s Omar Hellalat said a second draft of MTEP 15 has been posted and the RTO is currently accepting a second round of stakeholder feedback. These “substantive” comments are due Sept. 28; the feedback and MISO responses will be relayed to the MISO Board of Directors.
The PAC will hold a second discussion on the plan Oct. 14 before sending it on to the System Planning Committee for its October and November meetings. The MISO board will then take up the projects in December.
The first round of stakeholder feedback included grammatical and content comments and clarifying questions.
MISO is forecasting a 35% planning reserve margin for the winter and has implemented several changes to improve coordination with pipeline operators and ensure fuel deliveries to its fleet, Todd Ramey, vice president of system operations and market services, told FERC last week.
“We feel very comfortable that we have the resources and processes needed to ensure efficient operations for the coming winter,” Ramey said.
The RTO, which is forecasting a winter peak of 104 GW, is counting on installed capacity of 145 GW. MISO’s resource adequacy has come under scrutiny over the past two years, but concerns have been about meeting its summer peak. (See MISO Survey: No Shortfall Until 2020.)
Ramey said MISO has “new and improved” tools in its control room that increase situational awareness of pipeline conditions. In the past year, the RTO has also been conducting monthly calls with pipeline operators to share outage information, he said.
MISO has also implemented fuel surveys to gain greater awareness of the firmness of fuel deliveries to its gas-fired fleet, Ramey said.
In its first survey, conducted last year, only 15% of plants that responded had “primary firm” gas delivery, while 40% reported having “interruptible & other” arrangements; 24% of those surveyed did not respond. The RTO’s next survey will be in October, Ramey said.
MISO has also conducted informal fuel storage surveys. During the polar vortex, MISO found that generators’ coal inventories were lower than planned “due to some transportation disruptions,” Ramey said. He said that both inventories and rail supply are back to normal, but that the RTO would continue to keep an eye on them.
In response to a question from Commissioner Colette Honorable about the grid operators’ long-term objectives, Ramey said MISO was focused on working with state commissions as the region transitions from coal to natural gas.
Offer Cap
Ramey also said that MISO would make a filing concerning the $1,000/MWh energy market offer cap in the “next couple months.” He said stakeholders are still unsure about a final solution, but that the filing would at least address the cap for this winter. During the 2014 polar vortex, soaring natural gas prices pushed some generators’ costs over the cap.
The Northeast Energy Direct pipeline project through southern New Hampshire is the best way to lower electricity prices and increase reliability in New England, the staff of the state Public Utilities Commission concluded in a report released Wednesday.
The 48-page report examined three proposed pipeline expansions and an alternative for increased liquefied natural gas deliveries during the winter. The PUC ordered the study in the spring in response to high natural gas prices and concerns about reliability over the past two winters (IR15-124).
Kinder Morgan’s Northeast Energy Direct project would run on mostly new rights of way from Pennsylvania’s Marcellus Shale region through New York, Massachusetts and New Hampshire, terminating in Dracut, Mass. (See Kinder Morgan Trims Northeast Energy Direct.)
The Access Northeast project led by Eversource Energy and the Portland Natural Gas Transmission System, which would mostly expand pipelines on existing routes, provide lesser benefits, according to the report.
“We view Access Northeast and Northeast Energy Direct as two very cost-effective projects that will moderate future winter electricity prices, though the numbers clearly indicate that NED will provide the greatest benefits to regional electricity customers,” the report said.
Portland Natural Gas did not provide enough information for the PUC to conduct a thorough analysis, according to the report. The report added that Access Northeast would enhance reliability but would have less impact on gas prices.
“As a result of the NED project, [Kinder Morgan subsidiary] Tennessee Gas Pipeline will have the ability to physically deliver into every pipeline system serving New England, as well as to incrementally serve markets along its own pipeline system,” the report adds.
The report is less confident in the ability of LNG to fill in gas supply gaps, as it did during last winter.
“There is no guarantee that the market conditions that enticed LNG tankers to New England in winter 2014/15 will recur in future winters. This means the very high prices of 2013/14 could reappear just as quickly as they disappeared in 2014/15, assuming, of course, similar extreme weather conditions. Finally, it is important to note that the increased availability of LNG in winter 2014/15 did not eliminate price spikes or energy cost premiums,” the report said.
Seeking to improve its ability to unravel complicated market manipulation schemes, FERC last week proposed a new way for identifying connections between companies and individuals.
The commission issued a Notice of Proposed Rulemaking requiring RTOs and ISOs to begin registering market participants through common alpha-numeric identifiers, with lists of their “connected entities” and a description of their relationships (RM15-23).
The proposal would use a new system called Legal Entity Identifiers (LEIs), which are already used by the Commodity Futures Trading Commission and Securities and Exchange Commission to track swaps trades. FERC previously dropped use of the Data Universal Numbering System (DUNS), saying it was not effective for its purposes.
FERC said the new requirements will help the Office of Enforcement police market manipulation by providing a “more complete view of the relationships between market participants and the incentives underlying their trading activities.” The initiative would also help RTO market monitors in probes of cross-market manipulation, FERC said.
The office’s Division of Analytics and Surveillance runs automated screens to detect potential market manipulation. The office also has access to e-Tags, RTO trading data and information from the CFTC, including its Large Trader Report.
“Nonetheless, despite increased access to trading data, the commission cannot fully utilize this information in order to detect and deter market manipulation because of uncertainty regarding the identity of a given market participant, which may trade under different identifiers in different markets and venues,” FERC said. “The commission also lacks a clear window into the relationships between market participants and other entities, which can be complex. Without an understanding of which companies share ownership or debt interests, or who may function in key employment or other contractual roles (such as asset management), it can be difficult to ascertain which individuals or companies may benefit from a given transaction or, indeed, who may be jointly participating in a common course of conduct.”
‘Connected Entities’
The rule would require companies to identify all “connected entities,” a new term defined as those that have certain ownership, employment, debt or contractual relationships. It would replace current affiliate disclosure requirements contained in RTO and ISO tariffs unless the markets request their continuation.
FERC said it wanted a new definition “free of any associations that have developed around the term ‘affiliate,’ and one that is uniform across all of the RTOs and ISOs.”
Connected entities would include companies controlling more than 10% of another, as well as top executives and traders. The scope would extend beyond corporate affiliations, including contractual relationships such as tolling and asset management agreements and debt structures that are convertible to ownership interests.
FERC estimated that about 90% of reported wholesale electricity sales under commission jurisdiction are captured in Electric Quarterly Report data and affiliation information obtained from market-based rate filings and other sources. It sought comment on whether non-RTO market participants should also be required to make filings.
Companies would be required to file their connected entity data before being permitted to participate in RTO markets, and to verify their accuracy annually. FERC and the RTOs would be able to audit the filings to ensure compliance.
FERC said the change may ease compliance for market participants in multiple markets.
But in a concurring statement, Commissioner Cheryl LaFleur expressed concern that the rule “would create a significant new reporting regime for all market participants, as well as the RTOs and ISOs.” LaFleur said she might oppose the final rule if she concludes that “the benefits offered by new compliance obligations outweigh the burdens that will be faced by market participants.”
Comments on the rule will be due 60 days following publication in the Federal Register.
SPP is confident of its preparation for winter, although it will be adding the winter-peaking Integrated System to its footprint in October, Bruce Rew, SPP’s vice president of operations, told FERC.
The IS, which covers much of the Dakotas, will increase SPP’s load by about 15% and provide a contrast to the RTO, which is predominantly summer-peaking. “We don’t foresee any major … concerns for the winter,” Rew said, citing a 60% reserve margin.
SPP has included the IS in its annual winter assessment. It will hold a winter-preparedness workshop on Dec. 10 to cover emergency procedures and industry-wide lessons learned. Rew said gas pipeline representatives have been encouraged to attend, as they have in the past.
Rew said SPP has performed an analysis of this winter’s anticipated conditions and has determined additional actions are not needed. However, should extreme weather cause generation outages, the RTO would move to a “conservative operation alert.” These actions are discussed throughout the year in workshops and with stakeholders. Generally, SPP considers early committal of resources and delaying or postponing generation outages to ensure reliability.
The RTO has updated its regional weather-alert procedures, strengthening communication with gas pipelines, based on the footprint’s weather evaluations. An action plan has been developed and distributed to affected parties, Rew said.
SPP’s emergency operating plan includes criteria that require market participants to notify the SPP balancing authority when they anticipate fuel restrictions below certain thresholds. These notifications are intended to help prepare SPP before any larger fuel issues arise.
Rew said that SPP performs fuel-related assessments throughout the winter, depending on forecasted system conditions. Coordinated load-shed testing between SPP and transmission owners will begin this fall, and there will be weekly communication tests between SPP and participants.
The SPP gas-electric coordination task force has submitted a proposal in response to FERC Order 809 to better align the Integrated Marketplace’s timeline with gas nominations. Earlier posting of day-ahead market results leads to earlier posting of day-ahead reliability unit commitment results in time for the evening gas nomination. (See SPP Moving to 9:30 Day-Ahead Close.)
New York has adequate resources and improved operational practices to face the upcoming winter, a NYISO official told FERC on Thursday. But the infrastructure must still perform, Wes Yeomans, vice president for operations, told the commission.
New York still has a wide diversity of resources, with hydro at 11% of generating capacity and six nuclear facilities representing 14% of capacity, Yeomans said. But the overwhelming resource of choice is natural gas — representing 55% of capacity statewide and 95% in New York City.
More than 80% of gas generation can switch to oil when heating homes and businesses takes priority during cold snaps. “That really is the cornerstone of how we maintain reliability,” Yeomans said.
Natural gas prices in New York are generally far below that of diesel (bottom gray line), but price spikes occasionally made oil cheaper during the last two winters. (Top gray line: crude oil $/barrel)
But just because a resource has dual-fuel capability does not mean it would be available to switch to oil.
“A generator may have the capability to be dual-fuel, but they may make the business decision not to update their permits, or their maintenance, or add oil on-site,” he said.
Yeomans added that in New York, it may be financially advantageous for generators to have lower inventory on-site but rather have “fantastic arrangements” with suppliers to have access to inventory when needed. “Our experience has been that this works pretty good,” he said.
NYISO monitors its resource base through the seasonal generation fuel survey that was recently distributed.
One operational change effective Nov. 1 is an increase in the operating reserve requirement from 1,965 MW to 2,620 MW in day-ahead and real time. Reserve shortages would gradually raise prices and incent the market.
Forward reserve contracts will send price signals to generators “to go buy the fuel,” Yeomans said. “Having this reflected in our real-time pricing is a very significant step.”
Capacity margins in New York are about 10,000 MW but drop to a still-adequate 4,700 MW on a peak day during a once-in-10-year cold snap.
Other initiatives include site visits to units with low capacity factors to identify ways to improve performance. NYISO is also introducing a web-based, fuel survey “portal” that will go into production in December. This will provide the opportunity for generators to post fuel conditions to a video board for ISO operators replacing a manual process.
Yeomans said the ISO has become better at managing its morning ramp, which comes at the end of the gas day, resulting in fewer deratings of its gas generators.
After all the changes were described, the room erupted in nervous laughter when FERC Chairman Norman Bay asked Yeomans about his “comfort level” going into the winter.
ISO-NE said Chairman Philip Shapiro and board members Kathleen Abernathy and Roberta Brown have been re-elected, effective Oct. 1.
The RTO elects its board members through a nominating process that involves representatives from the current board, the New England Power Pool and the New England Conference of Public Utilities Commissioners.
Abernathy joined the board in 2012. Brown joined in 2007, while Shapiro joined in 2010 and was elected chairman in 2014.
Plains & Eastern Clean Line Nears Key Project Milestones
Clean Line Energy’s Plains & Eastern Clean Line is nearing a milestone as it awaits a key environmental report and the federal government’s decision whether to participate in the project.
The Energy Department is expected to complete a final environmental impact statement by late October for the 720-mile transmission line, which would deliver electricity generated by planned wind farms in Oklahoma and Texas to utilities in Tennessee and the southeast. The department will then decide whether to participate in the $2 billion HVDC transmission line. Under Section 1222 of the Energy Policy Act of 2005, the federal government can be involved with transmission projects to relieve electrical grid congestion or to increase transmission capacity.
Federal participation could range from operation, construction, development or ownership of some transmission assets. It would be structured through the Southwestern Power Administration, a federal agency that markets and transmits electricity from hydroelectric dams built by the U.S. Army Corps of Engineers to electric cooperatives, municipal electric authorities and other government users.
Invenergy 386-MW Gas Plant now Online in West Texas
Invenergy Clean Power earlier this month announced that its Ector County Energy Center, a 386-MW natural gas plant near Odessa, Texas, has begun operations.
The plant uses two GE 7FA simple-cycle combustion turbines fueled by Permian Basin natural gas. It is designed to provide peaking energy and respond quickly when ERCOT, the state’s grid operator, requests additional power supply.
NextEra Energy to Develop 300-MW Wind Farm in Texas
NextEra Energy has agreed to become the development partner of the Hale Community Wind Energy project in West Texas, according to project developer Tri Global Energy. The $7.3 million project encompasses more than 122,000 acres leased from about 350 landowners north of Lubbock.
Construction should begin in February or March, with the first turbines in operation by next summer. The project’s first phase is expected to be completed by Thanksgiving 2016.
No announcement has been made concerning power purchase agreements for the project’s expected 300 MW of generation. The energy production is expected to be used by municipalities, major corporations and electrical utilities. Hale Community Energy’s location enables it to supply energy to two major national power grids, ERCOT and SPP.
PSO to Add Solar Capacity, Increase Use of Wind Power
Public Service Company of Oklahoma (PSO) expects to add up to 200 MW of solar capacity and to bolster its wind offerings, according to a planning document outlined before regulators. The utility, which has 543,000 electricity customers in eastern and southwestern Oklahoma, presented its draft integrated resource plan at the Oklahoma Corporation Commission.
The plan represents PSO’s “best guess” at what its capacity and generation mix will look like by 2024. The utility expects to boost natural gas generation, continue to add wind capacity and to make a foray into utility-scale solar. Those changes come along with expected reductions in demand from various energy efficiency and conservation programs.
PSO expects to finish installing smart meters throughout its system by the end of 2016. It also has a pending case before state regulators to get reimbursed for $172 million in system investments and environmental compliance projects to meet federal regional haze rules and mercury and air toxics standards. If approved, the plan would increase residential customer bills 15% in the next year.
Minnesota Power will build the Northland’s first community solar garden next year, allowing customers to support solar energy without erecting solar panels on their homes or businesses.
The utility recently announced it will build a 40-kW solar array in Duluth that will be completed in 2016. The Duluth-based utility also plans a large 1-MW community solar array to be built by a contractor. Its energy production would be purchased by Minnesota Power and by customers who buy subscriptions. The two solar gardens — about 100 solar panels at the smaller site and 4,000 panels at the larger site — will generate enough electricity to power nearly 200 homes.
Both projects were submitted Sept. 10 to the Minnesota Public Utilities Commission, with approval expected in early 2016. Minnesota Power is required to comply with a state mandate to procure 1.5% of its retail electricity from solar energy by 2020.
Equipment Problem Forces Entergy’s Palisades Plant to Shut down Early
Entergy’s Palisades Nuclear Power Plant shut down four days earlier than the planned date for a refueling outage because of an equipment problem.
The plant, near South Haven, Mich., automatically shut down Wednesday when instruments detected a problem with the turbine generator system, the company said.
The problem with the system will be fixed during the refueling outage, the company said. During the planned outage, about a third of the reactor’s 204 fuel assemblies will be replaced.
Duke’s Lynn Good Named to Fortune’s Most Powerful Women List
Duke Energy President Lynn Good was ranked No. 13 on Fortune’s Most Powerful Women list this year. The magazine noted that the 56-year-old chief executive has spent a large part of her time dealing with a massive coal ash spill and other environmental issues.
The magazine’s online issue contained a video of a presentation she gave called, “How I dealt with an environmental disaster.”
Dynegy Wins Slot in MISO Zone 4 Procurement, ICC Says
The Illinois Commerce Commission named Dynegy as one of the winning suppliers of the Illinois Power Agency’s MISO Zone 4 Capacity Procurement event. Dynegy’s share of the awarded capacity was not announced, and the clearing prices remain confidential. The auction sets capacity for the planning year 2016/2017.
“The results of this RFP further validates Dynegy’s MISO investment thesis that the value of MISO capacity is rising as reserve margins tighten,” CEO Robert C. Flexon said.
The weighted average price was $138.12/MW-day. Total capacity provided by suppliers was 1,033 MW.
FERC last week upheld its decision requiring Northern States Power to continue purchasing electricity from a small hydroelectric plant, maintaining that the plant does not have access to MISO’s capacity market (QM15-2-001).
In its June request for rehearing, Northern States argued that FERC erred in requiring that the company show that Twin Cities Hydro, an 18-MW qualifying facility on the Mississippi River in Minnesota, had access to MISO’s markets. The Public Utility Regulatory Policies Act allows for the termination of the mandatory purchase of electricity from a QF if the generator has “nondiscriminatory” access to the markets.
FERC presumes that any QF with capacity less than 20 MW does not have access to the markets and requires utilities seeking to eliminate QF obligations to prove otherwise. In its May 14 order, FERC ruled that while Twin Cities had been selling power in MISO’s energy markets, it could not access the RTO’s capacity market. (See Ruling Denies Northern States’ Request to Halt Hydro Purchases.)
In its rehearing request, Northern States said the law “does not require a showing that the QF currently has met the requirements to sell its capacity into a market or a showing that the QF has had a history of sales. It simply requires a showing that the QF is on a level playing field with other facilities to establish nondiscriminatory access.”
It said FERC’s May 14 order allows Twin Cities, which is owned by Brookfield Renewable Power, to “sit on its hands and then be allowed to take advantage of the purchase requirement through its inaction.”
FERC was not persuaded by the arguments.
Northern States “has acknowledged that the Twin Cities QF cannot, at present, access the MISO capacity market,” FERC said. “The evidence presented by [Northern States’] own witness explained that, if Twin Cities were to submit a network resource interconnection service request, MISO would likely grant Twin Cities only conditional service, pending completion of several transmission network upgrades.”
The commission said the law requires that Twin Cities have “access to the specified markets and not merely that the Twin Cities QF is no more disadvantaged than any other sellers seeking to sell in such markets.”
Northern States also argued that FERC erred when it said that the company had to show access to an organized market, rather than merely a wholesale market.
The commission said no such thing, FERC said. Northern States’ “strawman argument that the May 14 order made such a finding — when, in fact, it did not — is thus without merit.”
Portland General Electric said Friday it will explore joining CAISO’s Energy Imbalance Market (EIM).
The EIM currently provides least-cost dispatch in California and parts of Oregon, Washington, Utah, Idaho and Wyoming, with Nevada-based NV Energy scheduled to join Nov. 1. Puget Sound Energy in Washington and Arizona Public Service plan to join in October 2016.
Also last week, the CAISO Board of Governors approved a proposed governance structure for the EIM. The governing body would have five members charged with representing real-time market participants’ interests, regardless of location. Changes in EIM market rules would have to be approved by the governing body and the ISO board before being filed with FERC.
Atlantic Coast Pipeline Files for Construction Permit with FERC
The owners of the Atlantic Coast Pipeline filed a formal request to FERC to construct the $5.1 billion, 564-mile pipeline to transport natural gas from the shale region of West Virginia to the Virginia and North Carolina coasts.
The owners, led by Dominion Resources and including AGL Resources and Piedmont Natural Gas, pre-filed the application about a year ago. Dominion, the operator, said it hopes to begin construction by the second half of 2016 and to complete it by the end of 2018.
The 30,000-page application asks FERC to declare the pipeline as a public benefit and necessity, which would allow the project to use eminent domain to obtain rights of way. Dominion says it has completed about 85% of the surveying for the project.
A look at the 99 operating nuclear generating stations in the U.S. in the first half of 2015 showed that 75 were operating at high levels and within all security and safety parameters, according to the Nuclear Regulatory Commission. A further 21 needed to resolve one or two low-significance safety items and will need an additional inspection, according to the commission.
But Arkansas Nuclear One Units 1 and 2 and Pilgrim nuclear plant were ranked substantially lower, on the commission’s “Multiple/Degraded Cornerstone Column,” or Column IV. Column V is “Unacceptable Performance Column” and calls for a plant to be shut down.
Pilgrim was marked down because of long-standing low-to-moderate safety findings. The plant’s operators are considering whether they can afford the costly upgrades and repairs required. If not, they say, they may shut down the plant.
Entergy, owner of Arkansas One, is set to brief the commission on steps it has taken to prepare for a major inspection of the plant. An NRC spokesman said about two dozen inspectors are expected to work “many weeks” to perform the full inspection.
NRC issued the poor rating for the plant after a fatal accident in March 2013, when a 500-ton generator part fell and crushed a worker and injured others. The incident also resulted in flooding in some parts of the plant.
Obama Administration Pledges $120 Million for Solar, Renewables
The Obama administration has pledged $120 million in funding to advance solar and other renewable energy technologies. The Department of Energy will oversee most of the programs, which are aimed at boosting solar in 24 states.
The White House noted that 734,000 homes now have solar panels, compared to 66,000 when President Obama came into office.
“President Obama and Vice President Biden are committed to promoting smart, simple, low-cost technologies to help America transition to cleaner and more distributed energy sources, help households save on their energy bills and to address climate change,” the White House said in a fact sheet outlining the efforts.
Nevadans Show up to Question NRC Report on Yucca Mountain
Nearly 100 people turned out at a public meeting to dispute a recently released Nuclear Regulatory Commission report that concluded that there would be “a negligible increase” in health risks if the Yucca Mountain underground nuclear waste repository were completed.
Richard Bryan, chairman of the Nevada Commission on Nuclear Projects, said the state was “steamrolled” into accepting the site, and said he’s not ready “to gamble on the health and safety of Nevadans” when it comes to Yucca Mountain.
The project is at a standstill, after the Obama administration cut off its funding in 2010.
FERC and the Nuclear Regulatory Commission are holding a joint meeting Oct. 21 at FERC headquarters in Washington. The two sets of commissioners will hold discussions during the first portion of the meeting, followed by staff presentations.
Representatives of the North American Electric Reliability Corp. are also expected to participate.
The Nuclear Regulatory Commission said that it is satisfied that PSEG Nuclear had addressed the issues that caused a series of unplanned shutdowns at the company’s Salem 1 station in Lower Alloways Creek Township, N.J., which prompted a higher level of attention from the regulatory agency.
NRC regulations call for a full review if a plant has more than three unplanned shutdowns in 7,000 hours of operation. Salem 1 had a fourth shutdown on Oct. 19. NRC said the company added new employee training to address the issues. The level of NRC oversight at the plant has dropped back down to normal levels.
Nation’s Utilities Perform Well After Fed Interest Rate Ruling
The stock prices of the nation’s electric utilities outperformed every other industrial sector following the Federal Reserve’s decision not to raise interest rates on Thursday.
The industry and investors were watching for the decision because utility stocks historically perform poorly when interest rates increase. The industry is capital-intensive, and utilities typically have to wait for rate increases to catch up with any interest rate increases.
“Interest rate increases are historically negative for utility stocks,” said Kit Konolige, a Bloomberg Intelligence senior utility analyst. “They react a lot like the way the bond market does when interest rates rise, which is negative.”
