VALLEY FORGE, Pa. — Two proposals that would have delayed the disclosure of financial transmission rights ownership following an auction were defeated by the Market Implementation Committee on Wednesday.
Bruce Bleiweis of DC Energy offered a package that would have allowed PJM to post aggregate data after an auction, mask ownership data for three to six months and disclose ownership after one year. It garnered only 10% of a sector-weighted vote.
A PJM proposal would have aligned the release of data with how the RTO treats other information, disclosing full ownership after four months. It received only 21% in a sector-weighted vote. (See “Proposals Would Delay Posting of FTR Ownership,” PJM Market Implementation Committee Briefs.)
Bleiweis said his proposal was intended to provide FTR owners the same confidentiality as other market participants.
The rejections were not a surprise. Several members and Market Monitor Joe Bowring had expressed opposition when Bleiweis won MIC approval of a problem statement to explore the issue in September.
Day-ahead Submission Deadline Moved up
Members endorsed updates to PJM’s regional transmission and energy scheduling practices intended to improve the alignment of the gas and electric markets.
A five-minute “shotgun” start window was created for hourly spot-in reservations (spot market imports), and the day-ahead bid submission deadline was moved from noon to 10:30 a.m.
Operating Parameter Definitions Approved
The committee approved short-term operating parameter definitions and voted to amend a problem statement to set June 1, 2017, as the deadline for permanent clarifications of the terms.
The amendment was proposed by Bob O’Connell of Main Line Electricity Market Consultants and included some clarifications to the terms cold/warm/hot start-up time, minimum run time and cold/warm/hot soak time.
PJM’s definitions were approved by 82% of the members in a sector-weighted vote. O’Connell’s definitions were approved by 60% of the vote. Both proposals will advance to the Markets and Reliability Committee, although O’Connell’s definitions will not be considered if PJM’s definitions are approved.
Clarifications Sought for Bilateral Transactions
Members approved a problem statement and issue charge to clarify rules on how auction-specific bilateral transactions credit bonus payments and indemnification. (See “PJM Proposes Clarifications to Capacity Bilateral Transactions,” PJM Market Implementation Committee Briefs.)
In such transactions, a seller transfers capacity to a buyer, but the obligation for performance remains with the seller.
The problem statement seeks to clarify how nonperformance charges and bonus payments apply to such transactions, and how they would be treated in litigation such as bankruptcies.
VALLEY FORGE, Pa. — PJM members last week approved manual and Tariff changes dictating the ramp rates Capacity Performance resources will have to meet to avoid penalties during performance assessment hours.
PJM said it found that many generators are able to increase their output faster than reflected in the ramp rates plant operators entered in Markets Gateway. The new rules will measure generators against the unit’s actual ramp performance between Jan. 1 and March 31, 2016 (or June 1 to Aug. 31, 2015, for units not dispatched in the first three months of this year).
Units would be excused from penalties if they are following PJM dispatch or had approved outages.
The approach is a short-term solution that PJM hopes to have in place before the delivery year starts June 1.
The Markets and Reliability and Members committees will be asked to endorse the changes on March 31, following a special OC session highlighting ramp rate examples on March 22.
PPL SPS to be Removed
A special protection scheme to prevent generator instability if the Susquehanna-Wescosville 500-kV line ever fell onto the Susquehanna-Harwood 230-kV lines is no longer needed with the addition of the Lackawanna-Hopatcong 500-kV line, according to PPL. The SPS — which would have resulted in tripping Susquehanna Unit 1 — will be removed during an outage of the nuclear unit and should be complete by April.
Dominion Zone SPS Retired
A special protection scheme installed in 2007 in the Dominion zone was retired last month. The SPS addressed potential thermal overloads on the Carolina-Kerr Dam 115-kV line. The scheme is no longer needed with the completion of Regional Transmission Expansion Plan project b1793 to rebuild Kerr Dam-Carolina line 22 and project b1793.1 to remove the Carolina 22 SPS.
VALLEY FORGE, Pa. — PJM and Dominion Resources are conducting an end-of-life review to prioritize upgrades on the utility’s system, a project that could result in the creation of proposal windows.
Of the 106 facilities being studied, about half are at the 230-kV level, with most of the rest split between 115-kV and 500-kV lines. In total, the review is considering 2,350 miles of transmission.
PJM already has verified the need for upgrades to two 500-kV facilities: the 82-mile Mt. Storm-Valley line and the 23-mile Valley-Dooms span. The RTO said the loss of either facility could cause thermal and voltage problems.
Although some transmission owners have criteria for end-of-life facilities, others do not, treating them as supplemental projects.
The Markets and Reliability Committee agreed last month to form a task force to develop RTO-wide criteria for end-of-life transmission facilities. Proponents said uniform guidelines would help planners prioritize equipment replacement. Just two of 12 Transmission Owners voted in favor of the proposal. (See PJM TOs Oppose Proposal to Develop End-of-Life Criteria.)
According to industry guidelines, wood structures can last 35 to 55 years, conductors and connectors 40 to 60 years and porcelain insulators 50 years.
Planners Select Dominion-Transource Project to Address APSouth Congestion
PJM planners have selected a $292 million project by Dominion High Voltage Holdings and Transource Energy to reduce congestion in the APSouth interface.
Pending reliability and sensitivity analyses, PJM planners intend to recommend the market efficiency project to the Board of Managers in April.
It would tap the Conemaugh-Hunterstown 500-kV line and build a new 230-kV double circuit line between Rice and Ringgold. The plan also calls for building a new 230-kV double circuit line between Furnace Run and Conastone and rebuilding the Conastone-Northwest 230-kV line.
Planners added $10 million to the proposed $282 million cost, saying additional upgrades were required at the Ringgold transformers. The projected in-service date is 2020.
The project was selected from among a dozen projects culled from responses to a proposal window last year.
Planners said that the benefits of most competing projects were hurt by the need for optimal capacitors, and that several projects that passed the 1.25:1 benefit-cost test have minimal impacts on APSouth or increase congestion elsewhere in the RTO.
PJM said the Dominion/Transource proposal (project 9A) “consistently ranked highest in most categories,” with a 2.66 B/C ratio and $31 million savings in annual production costs.
In a WebEx session Thursday, planners expect to release the results of the reliability analysis on the project as well as the sensitivity analysis on several combination projects. They also will identify designated entities.
PJM’s solution-based distribution factor cost allocation method is inappropriate in certain situations and an alternative scheme should be developed, the majority of commenters told FERC as the comment period on the issue closed last week (EL15-95).
FERC called for an inquiry in November in response to complaints over the cost allocation for two transmission projects: a stability fix for New Jersey’s Artificial Island nuclear complex and the Bergen-Linden Corridor upgrade.
FERC posed two questions: Is there a definable category of projects for which the DFAX cost allocation method might not be appropriate, and could a fair approach be developed for those occasions?
“Cost causation is the gold standard for allocation of new transmission projects,” wrote Hudson Transmission Partners and Neptune Regional Transmission System.
“When an analytical methodology hits the boundaries of its usefulness (and every model has such bounds), it starts to kick out unreasonable results,” they said. “The solution-based DFAX cost allocations for the New Jersey projects and for Artificial Island are jarring in their unreasonableness.”
PSE&G disagreed, saying the evidence “does not provide any basis for identifying one or more categories of [Regional Transmission Expansion Plan] projects for which the current solution-based DFAX cost allocation methodology does not provide a just and reasonable methodology for allocating costs commensurate with benefits. To the contrary, the cost allocation for each of the projects at issue in the underlying dockets is supported by the existing record.”
The transmission owners’ group concurred.
“Solution-based DFAX provides a just and reasonable measure of benefits from relative use over time for the vast majority of reliability projects in PJM,” the TOs wrote.
The remaining commenters said that DFAX should not be used to assign cost for projects not driven by flow-based issues, such as the stability fix at Artificial Island.
“The commission should direct PJM to modify the DFAX methodology to include load zone counterflow impacts in determining load zone impacts on that studied facility, to consider whether a project’s need is driven by flow-based issues, and to eliminate discriminatory post-analysis exceptions including the de minimis threshold,” wrote ITC Mid-Atlantic.
Wrote Consolidated Edison: “The record here, as developed at the technical conference, establishes that there is no rational relationship between energy flows and the intended benefits of non-overload projects.”
The Delaware Public Service Commission, together with the Maryland Public Service Commission, Delaware Division of Public Advocate and the Maryland Office of People’s Counsel, asked FERC to determine that stability-driven projects constitute a definable category for which the DFAX method should not be used.
Similarly, Old Dominion Electric Cooperative asked FERC to direct PJM to use an alternative cost allocation method for projects designed to address generator stability problems.
The D.C. Office of the People’s Counsel and Mayor Muriel Bowser’s administration came out Friday against Exelon’s revised merger proposal in filings that appear to quash the energy giant’s chances of acquiring Pepco Holdings Inc.
Sandra Mattavous-Frye
Neither the alternative offered by Public Service Commissioner Joanne Doddy Fort nor the options filed March 7 by Exelon guarantee “the type of rate protection I have been seeking in this case for almost two years,” said People’s Counsel Sandra Mattavous-Frye.
“Most critical to me were the benefits for residential ratepayers, particularly low-income residents who struggle to pay their electric bills,” she said. “OPC worked hard to achieve the guarantee of no rate increases for residential ratepayers through March 2019. We urge the PSC to resolve this issue expeditiously to bring closure for D.C. residents.”
In the March 7 joint filing, Exelon and PHI offered three options: Accept the agreement brokered by Mayor Muriel Bowser’s administration, which the commission rejected 2-1 Feb. 26; adopt the revision of that agreement that Fort and Commissioner Willie Phillips proposed; or agree to a new alternative that would provide $20 million in rate relief taken from funds earmarked for smart grid and environmental programs. It asked the PSC to rule by April 7. (See Exelon, Pepco Urge Compromise Deal to Win DC PSC OK for Merger.)
In a short filing on behalf of the D.C. government, Attorney General Karl Racine said the only acceptable option would be to accept the settlement that the PSC already rejected.
“The district continues to support the [settlement] as proposed on Oct. 6, 2015, and believes that approval of the merger on those terms provides direct and tangible benefits to ratepayers, promotes sustainability and otherwise remains in the public interest,” he wrote.
In a joint statement, Exelon and Pepco said, “Practically every party that filed comments today continues to believe the merger is in the public interest and supports its approval. The comments show differing opinions on how a portion of the more than $78 million in funds that Exelon has committed to the district should be used if the merger is approved. We hope the Public Service Commission will find a solution that secures all of the benefits for the district and Pepco’s customers and urge it to consider the alternatives we have outlined to approve the merger.”
Four other settling parties in the case also filed comments. The National Consumer Law Center, National Housing Trust and National Housing Trust-Enterprise Preservation Corp. rejected the revised settlement proffered by the commission but urged consideration of Exelon’s third alternative.
“Should option three be rejected, the merger is likely to collapse,” they said. “From the perspective of NCLC/NHT, this is contrary to the public interest, and particularly contrary to the interests of low-income households in the district.”
The Apartment and Office Building Association of Metropolitan Washington filed its support of Fort’s revised version of the settlement “as reasonable and in the public interest.”
“The proposed [revised settlement] clarifies the responsibilities of Exelon and Pepco in a post-merger environment, permits all ratepayers to participate in the benefits of the merger, ensures that funds that are intended to benefit ratepayers and improve Pepco’s electric system in the District of Columbia are not diverted to other purposes, and retains the commission’s statutory authority to enforce the terms and conditions of the [agreement],” it said.
The D.C. Water and Sewer Authority was the only settling party that did not file comments with the PSC, but it publicly has come out against the commission’s revised deal. The comment period is open through Thursday.
Anya Schoolman
Critics of the merger were pleased.
“Today’s filings are great news for D.C. residents and ratepayers,” said Anya Schoolman on behalf of the PowerDC coalition. “There is no viable path forward for Exelon’s attempt to take over Pepco. We agree with the Office of the People’s Counsel’s filing. D.C. is ready to move on.”
All took issue with the PSC’s requirement that $25.6 million earmarked for residential rate relief be held in escrow until the next Pepco rate case and then be considered for disbursement, including to nonresidential customers.
Exelon has spent an estimated $259 million over the past two years trying to capture Pepco’s $7 billion rate base.
CEO Chris Crane said in a Feb. 3 earnings call that the company was prepared to immediately begin buying back the 57.5 million shares it issued for the $6.8 billion deal if the merger fell through.
Friday’s news further weakened Pepco’s stock, which closed Monday at $22.22, down 8% from Friday’s open and down 16% from the open on Feb. 26, before the PSC rejected the mayor’s settlement. Exelon’s share closed Monday at $34.63, down almost 1% from the Friday open but up almost 9% since Feb. 26.
FERC ordered PJM last week to change its method of calculating capacity market offer caps, saying it was inconsistent with its practice in the energy market.
“We find that PJM’s Tariff is unjust and unreasonable because it allows the cost-based energy offer cap to be used as the sole measure of short-run marginal cost in calculating capacity market offer caps,” it said (EL14-94).
Harrison Power Station Source: FirstEnergy
“In the energy market, when a generation resource fails the three pivotal supplier test and submits a non-zero market-based offer less than its cost-based offer cap, PJM uses the lower, market-based offer, not the cost-based offer, as the basis for determining the resource’s commitment and dispatch,” FERC said. “When a resource is not subject to market power mitigation, PJM uses its offer as the basis for the resource’s commitment and dispatch. In both cases, PJM’s energy market relies on the offer, not the cap, as reflecting the resource’s short-run marginal cost.”
The ruling stemmed from a 2014 petition by FirstEnergy, which said PJM’s Independent Market Monitor was violating the Tariff by calculating marginal cost using the lower of the market-based offer and the cost-based offer.
But the commission ruled that the Monitor’s interpretation was appropriate and that the Tariff, which dictated use of cost-based offers only, was improper.
Joining FirstEnergy in support of the petition were PJM, Duke Energy, the PJM Power Providers Group and the Electric Power Supply Association. Opposing the petition were the Organization of PJM States, the Public Utilities Commission of Ohio, PJM Consumer Representatives, the Office of the Ohio Consumers’ Counsel and the Monitor.
FirstEnergy contended that cost-based offers are an accurate, transparent method for estimating marginal cost, and that market-based offers reflect factors other than marginal cost.
But the Monitor said using only cost-based offers could lead to the exercise of market power. For example, units that can use multiple fuels could base their higher, cost-based offers on their secondary fuel and their lower market-based offers on the primary fuel, the Monitor said.
The commission ordered PJM to submit a compliance filing specifying a new procedure using a resource’s non-zero market-based offer as proxy for marginal costs in most cases.
The cost-based offer would be used when the resource is mitigated and its market-based offer is above the cost-based offer cap, “as the market-based offer in this circumstance may reflect the exercise of market power,” FERC said.
The cost-based offer also would be used when the market-based offer is less than its fuel and environmental costs, “since the generator is losing money for each megawatt produced, a reasonable projection of its energy and ancillary services revenue should reflect such a reduction.”
A year after rolling out its extended LMP methodology, MISO plans to move into a second phase as it considers expanding online fast-start pricing to more peaking resources and investigating offline fast-start pricing.
MISO said it is considering using a 30-minute window instead of 10 minutes to summon fast-start resources. The change, according to MISO, could increase from 90 units contributing about 4,000 MW to 214 units contributing about 9,000 MW during summer peak capacity.
“Our intention is certainly not to raise prices, but to reflect the true price,” said Jeff Bladen, executive director of market services, told the Market Subcommittee last week. He said if unnecessary costs were hiding in the revenue sufficiency guarantee, including more resources would bring more transparency to ELMP.
“Phase II is meant to capture broader benefits,” MISO Market Design Engineer Congcong Wang said. “By expanding from 10 minutes to 30 minutes with fast-start resources, we would have the capacity almost doubled in terms of megawatts and units.”
Wang said studies on moving the fast-start window would be completed by August. MISO is targeting a FERC filing and new software testing for the first quarter of 2017.
Some stakeholders said it wasn’t reasonable to think fast-start resources would be able to commit to a five-minute interval and were afraid it would depress revenue sufficiency guarantee amounts. Others expressed concern that MISO would remain silent until August.
“This is not a proposal; it’s an investigation at this point. The purpose today is to let you know … we’re scoping out the project. We’re taking a lot of notes on what we’re hearing,” said Dhiman Chatterjee, MISO’s senior manager of market evaluation and design.
Chatterjee said MISO would provide stakeholders updates throughout the study process. He asked stakeholders to submit written questions and comments by March 15.
During the first six months of ELMP operations since last March, MISO said only about 40 units were enabled to set prices. MISO’s Independent Market Monitor said the number represented only about 1% of online peaking resources that were eligible to set prices.
MISO defines fast-start resources, which participate in price-setting, as those that can start within 10 minutes of notification and have a minimum run time of an hour or less.
So far, MISO said ELMP has resulted in “modest” benefits. Using ELMP has decreased uplift charges by 1%, a projected annual savings of more than $165,000. The RTO also said that the deviation between day-ahead and real-time prices was reduced by 2.25%.
More Info Sought from Load-Modifying Resources
Hoping to boost pricing accuracy during shortages, MISO will begin requiring market participants to identify the reductions each of their load-modifying resources will provide in an LMR event. The RTO is adding an additional form to its communications system to capture the data.
The other stages of MISO’s LMR reporting will be unaffected. Market participants will still use the system to report their daily LMR availability, with the RTO responding with scheduling instructions.
No date has been set for the change, but MISO hopes to have the additional reporting page active prior to the summer.
Jeff Knight of Entergy asked if participants could make changes on the form to select a different LMR to curtail without incurring additional charges. MISO Business Analyst Danielle Logsdon said market participants could make changes up to the hour before deployment.
“Just as baseball professionals are immersed in spring training for the upcoming season, this is preparation for emergency pricing implementation this summer, if it’s needed,” said Michael Robinson, MISO’s principal adviser of market design. “This is an effort to better set prices when we’re in these shortage conditions.”
Logsdon said MISO’s 2016 summer readiness training will be held April 14-May 19.
MISO Backs Make-Whole Fuel Payments
MISO has proposed reimbursing system support resources for unburned fuel when real-time schedules diverge from day-ahead schedules.
The RTO is also proposing that generation owners identify their fixed costs in filings with FERC. Currently, SSR units have to file directly with FERC only when MISO, the Monitor and the generation owner cannot negotiate a compensation agreement. MISO said having generation owners deal directly with FERC could reduce delays in implementing SSR agreements.
MISO said it “does not have independent information to evaluate SSR costs and relies on the generator owner for information on fixed cost compensation for the filing.”
Robinson said MISO would accept written comments until March 15. He said it is eyeing filing rule changes by the end of March.
Most Second-Tier Commercial Pricing Nodes Being Eliminated
MISO will terminate 28 second-tier commercial pricing nodes effective June 1. The changes will take effect with the 2016/17 financial transmission rights auction and the annual allocation process for auction revenue rights.
The RTO said it is jettisoning most of its second-tier interface commercial pricing nodes to “reduce administrative burden and be consistent with external balancing authority boundaries.”
“We reviewed these commercial pricing nodes and determined there is no business need for them,” said Zhaoxia Xie, MISO’s manager of modeling and market engineering.
MISO is evaluating the usefulness of six additional second-tier pricing nodes.
First-tier pricing nodes are associated with balancing authorities that are directly interconnected with MISO while second-tier nodes are not.
Illinois and Michigan Hub Definitions Changing
MISO is changing its Illinois and Michigan hub definitions as a result of the March 2016 model update, but the new descriptions are not expected to affect pricing substantially.
The Illinois and Michigan hubs will continue to have 151 and 265 elemental pricing nodes (EPNode), respectively. For both hubs, one EPNode was removed and replaced as a result of a substation closure.
For Illinois, the updated definition will reduce LMPs by less than a penny, according to MISO’s analysis, with average real-time prices expected to decrease from $25.13/MWh to about $25.12/MWh. In Michigan, the switch is projected to also amount to a penny reduction in day-ahead LMPs, from $25.91/MWh to $25.90/MWh.
Prices for MISO’s seven hubs are computed as the weighted average of the LMPs of the EPNodes comprising them.
Staff Considers Reusing Market Roadmap Information
MISO is considering reusing certain data in its Market Roadmap process to improve efficiency. The question of “prioritizing only new projects without reassessing existing projects” marked the beginning of the annual process at the MSC.
“What we’re looking for today is based on feedback we got at the tail-end of last year’s process. There were questions about the necessity of doing a full refresh of the Market Roadmap every year, where every item on the roadmap is looked at as it if were new or if we should only look at a subset of items,” Bladen said. For instance, Bladen said MISO’s roadmap could focus heavily on forward-looking projects beyond 2017 while using existing information for other projects.
MISO’s Mia Adams said the RTO was looking for feedback on the proposal by the end of the month.
MISO could have a limited set of market rules for energy storage as early as 2017, RTO officials told the Market Subcommittee last week.
AES’ 20-MW energy storage array in Indianapolis, expected to go into operation in June, will be the first utility-level battery energy storage facility in MISO. Source: AES Energy Storage
MISO External Affairs Policy Advisor Jennifer Richardson said storage provisions could be a “combination of using established definitions” and creating new market rules.
In the near term, MISO said it will work with stakeholders on minor revisions to the Tariff and business practice manuals that would open the market to short-term and medium-term storage. By summer, MISO hopes to have a clear idea if storage should be treated as a generation resource or a transmission asset and whether it can participate in MISO’s capacity or ancillary service markets. For that, MISO needs to consider how behind-the-meter storage can function as load-modifying resources or demand response.
AES Project Nears Completion
The storage conversation comes as AES’ Indianapolis Power & Light edges closer to finishing the 20-MW Advancion Energy Storage Array in Indianapolis. The project, slated to be put into operation sometime in June, will be the first utility-level battery energy storage facility in the footprint.
“A lot of stakeholder comments focused on developing new software,” said Yonghong Chen, MISO’s principal advisor of market development and analysis, during a presentation to the subcommittee. “In the next few months, probably from April to July, we’re going to work with stakeholders to determine what we can do [with existing software]. By next year, we hope to have implementation rules on how storage can participate with our current market software and market rules. … We have some existing language in the Tariff and BPMs that could apply, but some language needs clarification to apply to storage.”
From mid-2017 onward, MISO plans to tackle how storage will fit into five-minute settlement schedules, voltage and local reliability commitments, minimum megawatt participation limits and automatic generation control enhancement, software that deploys fast ramping resources more quickly.
“We want to remain as technology-neutral as possible, but FERC may have to step in at some point,” Richardson said.
AES’ 20-MW storage facility will have the flexibility of a 40-MW resources. Source: AES Energy Storage
Long-Term Plans
MISO said its longer-term storage considerations would run into 2019 and include make-whole payments, cost allocation and impacts to the annual Transmission Expansion Plan.
“We need more time to figure out how to make these work well together,” Chen said.
Jeff Bladen, MISO’s executive director of market design, said storage should work “holistically” with MISO’s market.
“This is very much a topic on stakeholders’ minds, as they’re thinking of developing projects and bringing them to market,” he said. “We have to be careful not to put energy storage into its own silo. It needs to fit into the larger Market Roadmap.”
Stakeholder Comments
Ameren told MISO that it believes energy storage could be categorized as “generation, transmission or other, depending upon its characteristics.” The company proposed that MISO classify storage as a use-limited resource, then perform an “initial asset evaluation” to determine if it should be treated as a generator or transmission asset. Use-limited resources are those “unable to operate continuously on a daily basis, but … able to operate for a minimum set of consecutive operating hours.”
Madison Gas and Electric said storage could fit into a generation or transmission definition. The company went a step further, suggesting that MISO remove prescriptive resource definitions from the Tariff altogether. “To be agnostic or ‘neutral’ when it comes to technology, then we need to be neutral as to what type of resource provides services. The Tariff lists the products and services permitted by each resource type. To become neutral, we should remove prescriptive/descriptive limitations and allow resources to provide any product or service for which it can satisfactorily deliver. We can test and measure performance of resources, eliminating the need to limit products/services by resource type,” Madison’s Megan Wisersky wrote MISO.
ITC Holdings advocated leaving storage unclassified, saying it was “premature” to categorize the technology when it hadn’t yet been integrated into the grid.
Amber Motley, manager of market operations for Xcel Energy, said market participants should be given the option of choosing to categorize storage as either generation or transmission, a position supported by MidAmerican Energy.
Chen said work on energy storage rules would play out in MISO’s Planning Subcommittee and Resource Adequacy Subcommittee, as well as other committees, if needed.
“We’re very mindful that stakeholders don’t want to chase these issues in a hundred different committees. Believe me, we don’t want that either. We’ll try our best to iron out those hard questions internally before we bring them to stakeholders,” Richardson said.
Chen asked for another round of stakeholder input before March 18.
A Pennsylvania-based power trading company accused by FERC of making riskless up-to-congestion transactions to collect line loss payments denied any wrongdoing Friday and requested the matter be dismissed.
Coaltrain Energy said that it didn’t manipulate the market, that its trading strategy wasn’t deceptive and that it didn’t engage in wash trades or try to affect market prices (IN16-4).
If the commission doesn’t terminate the case, Coaltrain said it will seek a de novo trial, with a federal court deciding all issues of fact and law, rather than the company potentially appealing an unfavorable FERC ruling afterward.
One of the allegations levied by FERC was that Coaltrain’s use of employee-monitoring software gave investigators evidence of the company’s trading strategy. FERC said Coaltrain employees at first claimed they had forgotten about the software — Spector 360 — when the Office of Enforcement initially asked, and then repeatedly delayed giving up the data. (See FERC: Spy Software Provides Evidence of UTC Scam.)
In its response, Coaltrain denied attempting to conceal the data, which included logs of the company’s trading.
“What actually happened is that it simply did not occur to the individuals involved that Spector 360 was a source of potentially responsive material at the time they were working on Coaltrain’s initial document responses,” the company said. “As soon as the issue was identified, Coaltrain promptly provided this data. The data was exculpatory, not inculpatory and there was no reason to conceal it.”
The response revealed that the owners of Coaltrain, Shawn Sheehan and Peter Jones, did not have Spector 360 installed on their computers, and so their actions would not have been recorded.
The response also says that Coaltrain had several communications with PJM’s Independent Market Monitor, Joe Bowring, and provided FERC with recordings of those discussions. “The content and context of these calls demonstrate that Coaltrain provided the IMM with accurate, truthful information that specifically addressed each of the IMM’s stated concerns,” the company said.
In one discussion, Bowring answered that he considered trades to be illegitimate if “the only reason you’re making money from the transaction is you’re buying and selling at the same price, and making money entirely from the payback of the marginal losses. Dr. Bowring reiterated that, in his view, Coaltrain’s trades were ‘not violating the rules.’”
When Bowring later expressed concern over Coaltrain’s trades, the company said, “Coaltrain agreed to halt trades on specific paths and followed through on that promise.”
FERC is seeking $42 million in penalties and unjust profits.
Indianapolis Power & Light’s Harding Street power plant, one of Indiana’s largest, will kick its coal habit completely by spring.
The company announced a $70 million investment to switch the plant to natural gas in 2014, and the conversion is expected to be complete in April, subject to approval by the state’s Utility Regulatory Commission. Coal has been Harding Street’s sole source of energy since the plant began operations in 1931.
IPL anticipates that the move will decrease its reliance on coal from 79% in 2007 to 44% in 2017. The company hasn’t yet said how many jobs might be affected by the change. During 2015, the state lost 500 coal-related jobs.
American Transmission Co. is planning a new transmission line for 2020 to improve the flow of electricity from Wisconsin to Illinois.
The 3- to 5-mile segment targets the same location as a 345-kV line that opened in 2013 between Pleasant Prairie, Wis., and a natural gas-fired power plant in Lake County, Ill.
Since then, “market conditions have continued to change in Wisconsin and Illinois, leading to unanticipated congestion in the Wisconsin-Illinois electrical interface,” an ATC spokesperson said. “This project is needed to resolve that.”
Ameren Official Named to ‘Most Influential Blacks’ List
Mark
Ameren Illinois President Richard Mark has been named one of Savoy Magazine’s Top 100 Most Influential Blacks in Corporate America, earning the distinction for the second time.
The magazine selects black leaders “who have made a positive impact in corporate America and have made a difference in the communities where they live and work.”
Mark was named president of Ameren Illinois in June 2012.
“Richard is not only a great leader in our organization, but he is a champion for the customers we serve and a true leader in the community,” Ameren CEO Warner Baxter said.
Hunt’s Proposed REIT Structure Could Scuttle Oncor Purchase
Two of three commissioners on the Public Utility Commission of Texas indicated last week they would only allow a consortium led by Dallas billionaire Ray Hunt to buy Oncor if some of the tax savings created by the sale are funneled back to consumers.
Commissioners Kenneth Anderson and Brandy Marty Marquez made clear during a March 3 hearing in Austin they will only support what they call a “risky” real estate investment trust (REIT) structure if Oncor’s more than 3 million ratepayers get to share in the tax savings.
That stipulation could be a deal breaker for the Hunt group, which would attempt to transform the Dallas-based transmission company — the state’s largest — into a REIT. The pending sale has attracted attention beyond Dallas because it could set a precedent for other utilities to become such trusts, including CenterPoint Energy, which is considering the same path.
Duke Energy said it will build a 6-MW solar facility on 50 acres in Rowan County, N.C., the third solar project the company hopes to complete in the state in 2016. If approved by the Utilities Commission, the plant should be online by the end of the year.
Duke is nearing completion of 141 MW of solar projects begun in the state last year and has announced plans to construct an additional 81 MW of solar this year. A 60-MW project is planned for near Monroe and a 15.4-MW facility is to be built in Mocksville.
EDP Renewables could add as many as 49 new wind turbines to the southwestern Wisconsin landscape by 2017 with a 98-MW project located in Seymour Township. The company said the project would create 10 to 15 full-time, permanent jobs and support more than 200 temporary construction jobs.
Josh Bohach, project manager for EDP Renewables, said workers will begin construction in 2017 and spend this year finishing surveying and design work. Jack Sauer, chairman of the Lafayette County Board, said the wind project has been under discussion for more than a decade, with grid interconnection alone taking years to hash out.
“It seems like with some of the bigger projects, you get your hopes up and they take a long time to come together or never get here at all,” Sauer said. “I think a lot of people are a little surprised to see it finally coming together now.”
Oklahoma Gas and Electric is moving up the timeline for constructing a $190 million transmission line to help connect wind farms in northwestern Oklahoma, company executives said Feb. 26.
The utility will begin building the 126-mile 345-kV Windspeed II line from Woodward near the Texas Panhandle to its Cimarron substation northwest of Oklahoma City early next year. The line is expected to be in service by mid-2018, three years earlier than expected.
OG&E said the line will relieve congestion issues in northwestern Oklahoma, one of the reasons OG&E declined to commit to additional wind generation during a long-running, $1.1 billion environmental compliance and replacement generation case at the Oklahoma Corporation Commission.
DTE Energy said it will make multiple shifts in its senior executive structure on April 4.
Company President and COO Steve Kurmas will be appointed vice chairman, while Jerry Norcia, currently president and COO of DTE Electric and Gas Storage and Pipelines, will assume Kurmas’ role.
Kurmas’ new position will have him overseeing multiple large-scale projects, despite his plans to retire in 2017, ending a 38-year run with DTE. Norcia has 14 years’ experience at the company and will head electric and gas business operations, major enterprise projects and the customer service division.
Norcia’s position will be filled by Trevor Lauer, currently senior vice president of DTE’s distribution operations. Lauer joined DTE in 2005.
SPS Energizes $39M Project to Meet Texas, NM Demand
Southwestern Public Service last week activated a new $39 million, 38-mile addition to its transmission network in the eastern Texas Panhandle to meet growing demand and increase reliability, one of several SPP-approved projects to improve service in the region.
The improvements could eventually have a financial impact on customers of the Xcel Energy subsidiary, which already has a request for a $71.9 million annual rate increase pending before the Public Utility Commission of Texas. That request doesn’t include the most recent construction.
Since July 2014, SPS has invested about $1 billion on system additions in service by the end of last year, part of an overall $3 billion plan to make improvements in its Texas and New Mexico service areas by 2020.
NRG Energy posted a $6.36 billion loss for the last quarter of 2015 and announced it would slash its annual dividend by nearly 80% to 12 cents/share, saving about $145 million a year.
The full-year loss of $6.44 billion translated into $19.46/share. NRG attributed its poor performance in part to the plunge in commodity prices, which weighed on the company’s coal fleet.
The company also announced that it would reintegrate its NRG Renew business back into the flagship operation after creating the renewables arm just last year.
Under longtime CEO David Crane, NRG made strong moves into renewable energy, solar power and vehicle charging units. Crane was ousted in December after results came up short and replaced by COO Mauricio Gutierrez, who last week said NRG will now concentrate on merchant generation and retail energy sales.
Invenergy Planning Wind Farm near Bloomington, Ill.
Invenergy is approaching landowners as it works on plans to construct a 120-turbine wind farm it seeks to have online by the end of 2017. Business development manager Allyson Sand said the company is looking in four different townships near Bloomington for sites for the facility, expected to be rated at 200 to 250 MW.
Sand would not discuss the costs of the project, but she said Invenergy expects to file for permits and arrange a power purchase agreement by the end of this year.
The region is seeing a spike in wind project planning and development, with a 240-turbine farm being planned for eastern McLean County. A wind farm in neighboring LaSalle County produced $1.79 million in tax revenue for the county last year.
Fermi 2, Davis-Besse Both Running at Reduced Levels
Fermi nuclear plant
Separate, coincidental equipment problems left two Ohio nuclear plants operating at reduced levels last week.
The reactor at DTE Energy’s Fermi 2 was powered down to 59% to allow for repairs on a feedwater system valve. FirstEnergy’s Davis-Besse plant was reduced to 85% after mistaken signals were sent to its auxiliary feedwater system. That problem was fixed, but the plant operated at 100% for only two days before coasting down in anticipation of a scheduled refueling outage.
St. Louis-based Foresight Energy last week asked the federal Mine Safety and Health Administration to close the company’s central Illinois coal mine, the site of an underground fire burning since mid-2014.
The company hopes the fire in the Deer Run Mine near Hillsboro will be choked off if the mine is allowed to be sealed off temporarily. Foresight has tried to extinguish the fire by sealing off some mine sections and filling them with inert gas and extinguishing chemicals. In December, the company evacuated the longwall mine, then laid off 100 employees. By January, the company had stopped mine production altogether due to low demand for coal and high carbon monoxide levels underground.
The coal producer is also seeking authorization from the Illinois Commerce Commission to expand mining operations into areas unaffected by the fire.
Groundbreaking Held for Navy’s Seabee Base Solar Plant
Mississippi Power held groundbreaking ceremonies March 2 for its proposed Seabee Base solar plant. The company is partnering with Hannah Solar and the U.S. Navy on the 23-acre, 3- to 4-MW solar project at the base in Gulfport, Miss.
The project, consisting of about 13,000 panels, will be able to provide power for approximately 450 homes.
“This is one of three utility-scale solar projects that have been approved by the Mississippi Public Service Commission, making our company the state’s largest partner in renewable energy,” Mississippi Power CEO Anthony Wilson said.
Indianapolis Power & Light’s Harding Street power plant, one of Indiana’s largest, will kick its coal habit completely by spring.
American Transmission Co. is planning a new transmission line for 2020 to improve the flow of electricity from Wisconsin to Illinois.
Two of three commissioners on the Public Utility Commission of Texas indicated last week they would only allow a consortium led by Dallas billionaire Ray Hunt to buy Oncor if some of the tax savings created by the sale are funneled back to consumers.
Duke Energy said it will build a 6-MW solar facility on 50 acres in Rowan County, N.C., the third solar project the company hopes to complete in the state in 2016. If approved by the Utilities Commission, the plant should be online by the end of the year.
EDP Renewables could add as many as 49 new wind turbines to the southwestern Wisconsin landscape by 2017 with a 98-MW project located in Seymour Township. The company said the project would create 10 to 15 full-time, permanent jobs and support more than 200 temporary construction jobs.
Oklahoma Gas and Electric is moving up the timeline for constructing a $190 million transmission line to help connect wind farms in northwestern Oklahoma, company executives said Feb. 26.
NRG Energy posted a $6.36 billion loss for the last quarter of 2015 and announced it would slash its annual dividend by nearly 80% to 12 cents/share, saving about $145 million a year.
Invenergy is approaching landowners as it works on plans to construct a 120-turbine wind farm it seeks to have online by the end of 2017. Business development manager Allyson Sand said the company is looking in four different townships near Bloomington for sites for the facility, expected to be rated at 200 to 250 MW.
St. Louis-based Foresight Energy last week asked the federal Mine Safety and Health Administration to close the company’s central Illinois coal mine, the site of an underground fire burning since mid-2014.