The New Jersey Board of Public Utilities has opened an investigation into "how the State can best achieve its reliability, clean energy, and environmental objectives, while keeping costs to consumers as low as possible." Like many states, New Jersey’s utilities participate in a
federally regulated regional transmission organization’s capacity
market, but are also subject to state clean energy laws -- a tension
that has caused the state's energy regulators to consider whether to
leave the PJM regional capacity market.
At issue is whether New Jersey can "achieve its long-term clean energy and environmental objectives under the current resource adequacy procurement paradigm" -- the regional electric capacity market operated by PJM Interconnection -- or whether it should adopt an alternative mechanism to "meet New Jersey’s resource adequacy needs in a manner consistent with
the State’s clean energy and environmental objectives, while considering
costs to utility customers."
New Jersey electric utilities currently participate in the PJM regional markets, including a capacity market. The state has adopted a 2019 Energy Master Plan: Pathway to 2050, establishing a series of state-focused clean energy goals such as 7,500 MW of offshore wind by 2035 and 100% clean energy by 2050. Other states in the PJM region have adopted different clean energy goals.
At the same time, PJM's regional market is federally regulated. In December 2019, the Federal Energy Regulatory Commission directed PJM to modify its "Minimum Offer Price Rule" or MOPR, governing the capacity
market. Designed to counteract excessive market power, the federal ruling directed PJM to modify its MOPR to also counteract the pricing effects of state clean energy
policies. In its state Energy Master Plan, New Jersey described FERC's action as "actively attempting to support fossil fuel interests in the [PJM] region under the guise of promoting ‘fair’ competition."
In response to the FERC's MOPR order, on March 27, the New Jersey Board of Public Utilities issued an Order Initiating Proceeding in Docket No. EO20030203. Citing the federal order, the Board characterized it as "a direct attack on the State’s clean energy programs" and expressed concern that continued participation in the federally-regulated PJM market could frustrate New Jersey's ability to achieve its clean energy goals. The Board thus initiated a proceeding to consider whether to retain the current PJM market paradigm, or whether an alternative could achieve the state's climate and environmental goals at a lower cost to consumers.
Withdrawing from a regional transmission organization can be done under certain circumstances, but federally regulated tariffs and territories spanning multiple states with their own laws can complicate the path toward a clean break. As envisioned by the Board, possible alternatives for New Jersey might include using a "fixed resource requirement" or FRR approach under the PJM tariff to effectively withdraw one or more service areas from the broader PJM capacity market, or adopting a statewide clean energy standard that would require load-serving entities to source increased percentages of renewable or other clean energy.
Board staff subsequently issued a Request for Written Comments in the proceeding, soliciting written comments on four sets of topics by April 29. Issues raised in the request for comment include whether New Jersey could utilize the Fixed Resource Requirement alternative to satisfy its resource adequacy needs and accelerate its clean energy goals, whether modifications to the Board's Basic General Service construct could facilitate resource adequacy procurements aligned with the state's Energy Master Plan, and whether other mechanisms such as a clean energy standard or clean energy market could facilitate achievement of the state's clean energy goals.
Staff have suggested the Board's investigation will be completed later this year.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Showing posts with label PJM. Show all posts
Showing posts with label PJM. Show all posts
FERC approves energy storage tariffs
Wednesday, October 23, 2019
U.S. utility regulators have approved the first two regional implementations of a landmark 2018 order designed to remove barriers to the participation of electricity storage in wholesale markets.
In 2018, the Federal Energy Regulatory Commission issued its Order No. 841, requiring each organized power market to revise its tariff to establish a "participation model" for electric storage resources in the capacity, energy and ancillary service markets. The rule requires each market's participation model to include market rules that recognize the physical and operational characteristics of electric storage resources and facilitate their participation in those markets. The Commission later affirmed the rule, through its Order No. 841-A.
Last week, the Commission issued two orders approving Order No. 841 compliance filings by Southwest Power Pool, Inc. and by PJM Interconnection. The Commission generally found that the SPP and PJM tariff revisions complied with the new rule, and largely accepted their filings. For example, the Commission found that both proposals "generally enable electric storage resources to provide all services they are capable of providing; allow electric storage resources to be compensated for those services in the same manner as other resources; and appropriately recognize the unique physical and operational characteristics of electric storage resources."
However, the Commission also provided directives for further compliance filings by SPP and PJM to be made within 60 days. The Commission found that while both filed tariffs generally satisfy Order No. 841’s directive allowing electric storage resources to de-rate their capacity to meet minimum run-time requirements, neither tariff included minimum run-time requirements for resource adequacy and capacity, respectively. Because "such requirements affect rates, terms and conditions of service," the Commission initiated proceedings under section 206 of the Federal Power Act to address the specific issue of minimum run-time requirements.
In a pair of separate statements (on SPP and on PJM), Commissioner McNamee concurred with the orders insofar as they found compliance with the Commission's orders and regulations. But Commissioner McNamee said, "I write separately, however, to express my continuing concern that the Commission exceeded its statutory authority under the Federal Power Act, and should have, at the very least, provided states the opportunity to opt-out of the participation model created by the Storage Orders." Commissioner McNamee also reiterated jurisdictional concerns he had previously raised in a partial concurrence to and partial dissent from Order No. 841-A, "to the extent the Commission’s Storage Orders exercised authority over the distribution system and behind-the-meter."
Other organized wholesale market operators, such as ISO New England, Inc., are also adopting tariff revisions to comply with Order No. 841, to enhance the ability of electric storage facilities to participate in regional wholesale electricity markets.
In 2018, the Federal Energy Regulatory Commission issued its Order No. 841, requiring each organized power market to revise its tariff to establish a "participation model" for electric storage resources in the capacity, energy and ancillary service markets. The rule requires each market's participation model to include market rules that recognize the physical and operational characteristics of electric storage resources and facilitate their participation in those markets. The Commission later affirmed the rule, through its Order No. 841-A.
Last week, the Commission issued two orders approving Order No. 841 compliance filings by Southwest Power Pool, Inc. and by PJM Interconnection. The Commission generally found that the SPP and PJM tariff revisions complied with the new rule, and largely accepted their filings. For example, the Commission found that both proposals "generally enable electric storage resources to provide all services they are capable of providing; allow electric storage resources to be compensated for those services in the same manner as other resources; and appropriately recognize the unique physical and operational characteristics of electric storage resources."
However, the Commission also provided directives for further compliance filings by SPP and PJM to be made within 60 days. The Commission found that while both filed tariffs generally satisfy Order No. 841’s directive allowing electric storage resources to de-rate their capacity to meet minimum run-time requirements, neither tariff included minimum run-time requirements for resource adequacy and capacity, respectively. Because "such requirements affect rates, terms and conditions of service," the Commission initiated proceedings under section 206 of the Federal Power Act to address the specific issue of minimum run-time requirements.
In a pair of separate statements (on SPP and on PJM), Commissioner McNamee concurred with the orders insofar as they found compliance with the Commission's orders and regulations. But Commissioner McNamee said, "I write separately, however, to express my continuing concern that the Commission exceeded its statutory authority under the Federal Power Act, and should have, at the very least, provided states the opportunity to opt-out of the participation model created by the Storage Orders." Commissioner McNamee also reiterated jurisdictional concerns he had previously raised in a partial concurrence to and partial dissent from Order No. 841-A, "to the extent the Commission’s Storage Orders exercised authority over the distribution system and behind-the-meter."
Other organized wholesale market operators, such as ISO New England, Inc., are also adopting tariff revisions to comply with Order No. 841, to enhance the ability of electric storage facilities to participate in regional wholesale electricity markets.
FERC assesses Coaltrain penalties
Wednesday, June 1, 2016
U.S. energy regulators have issued an order assessing $38 million in civil penalties for alleged energy market manipulation, plus disgorgement of unjust profits.
The case involves Coaltrain Energy, L.P., two of its individual owners, and three traders. In January 2016, the Commission issued an Order to Show Cause and Notice of Proposed Penalty, alleging that the respondents had engaged in fraudulent transactions in PJM Interconnection L.L.C.'s energy markets. The show cause order, and a supporting Enforcement Staff Report, also include allegations that Coaltrain made false and misleading statements and material omissions during the Commission's investigation.
FERC's case against Coaltrain has now moved forward. In a May 27 order, the Federal Energy Regulatory Commission found that Coaltrain and five named individuals violated section 222 of the Federal Power Act and section 1c.2 of the Commission’s regulations, which prohibit energy market manipulation, through a scheme to engage in fraudulent Up-To Congestion (UTC) transactions to garner excessive amounts of certain credit payments to transmission customers.
According to the Commission, the Coaltrain respondents engaged in UTC trading conduct "similar to the behavior the Commission found fraudulent in its Chen and City Power orders issued last year," in that the UTCs were traded "not to profit based on price spread arbitrage, as the product was designed, but instead, to profit solely or primarily from a transmission credit that had nothing to do with the underlying product." FERC alleges that the Coaltrain respondents "designed and implemented a fraudulent UTC trading scheme to receive excessive amounts of MLSA payments," or Marginal Loss Supply Allocation transmission credits. In the Commission's words, "Respondents’ OCL Trades were manipulative because they were executed for the sole or primary purpose of targeting and garnering MLSA payments. Additionally, they were manipulative because they falsely appeared to PJM as being placed for the market design purpose of arbitraging price spreads, thus concealing their fraudulent nature and purpose."
The Order Assessing Civil Penalties also found that Coaltrain violated section 35.41(b) of the Commission's regulations, which in relevant part, prohibits a seller, such as Coaltrain, from submitting false or misleading information to or omitting material information from Commission staff. The Commission found that in the course of responding to an investigation by FERC Office of Enforcement staff, Coaltrain intentionally withheld relevant documents from Commission staff while repeatedly representing to that its productions were “true, complete, and accurate.” In particular, FERC concluded that Coaltrain held back documents recorded on its Spector 360 keystroke logging software discussing and reflecting its trading strategy, and only produced the documents to the Commission after agency staff discovered the documents' existence on their own.
The May 27 order states that based on the "seriousness of these violations," it is appropriate to assess civil penalties pursuant to section 316A(b) of the Federal Power Act in the following amounts:
The case involves Coaltrain Energy, L.P., two of its individual owners, and three traders. In January 2016, the Commission issued an Order to Show Cause and Notice of Proposed Penalty, alleging that the respondents had engaged in fraudulent transactions in PJM Interconnection L.L.C.'s energy markets. The show cause order, and a supporting Enforcement Staff Report, also include allegations that Coaltrain made false and misleading statements and material omissions during the Commission's investigation.
FERC's case against Coaltrain has now moved forward. In a May 27 order, the Federal Energy Regulatory Commission found that Coaltrain and five named individuals violated section 222 of the Federal Power Act and section 1c.2 of the Commission’s regulations, which prohibit energy market manipulation, through a scheme to engage in fraudulent Up-To Congestion (UTC) transactions to garner excessive amounts of certain credit payments to transmission customers.
According to the Commission, the Coaltrain respondents engaged in UTC trading conduct "similar to the behavior the Commission found fraudulent in its Chen and City Power orders issued last year," in that the UTCs were traded "not to profit based on price spread arbitrage, as the product was designed, but instead, to profit solely or primarily from a transmission credit that had nothing to do with the underlying product." FERC alleges that the Coaltrain respondents "designed and implemented a fraudulent UTC trading scheme to receive excessive amounts of MLSA payments," or Marginal Loss Supply Allocation transmission credits. In the Commission's words, "Respondents’ OCL Trades were manipulative because they were executed for the sole or primary purpose of targeting and garnering MLSA payments. Additionally, they were manipulative because they falsely appeared to PJM as being placed for the market design purpose of arbitraging price spreads, thus concealing their fraudulent nature and purpose."
The Order Assessing Civil Penalties also found that Coaltrain violated section 35.41(b) of the Commission's regulations, which in relevant part, prohibits a seller, such as Coaltrain, from submitting false or misleading information to or omitting material information from Commission staff. The Commission found that in the course of responding to an investigation by FERC Office of Enforcement staff, Coaltrain intentionally withheld relevant documents from Commission staff while repeatedly representing to that its productions were “true, complete, and accurate.” In particular, FERC concluded that Coaltrain held back documents recorded on its Spector 360 keystroke logging software discussing and reflecting its trading strategy, and only produced the documents to the Commission after agency staff discovered the documents' existence on their own.
The May 27 order states that based on the "seriousness of these violations," it is appropriate to assess civil penalties pursuant to section 316A(b) of the Federal Power Act in the following amounts:
$26,000,000 against Coaltrain (jointly and severally with Messrs. Peter Jones and Sheehan); $5,000,000 against Mr. Peter Jones; $5,000,000 against Mr. Sheehan; $1,000,000 against Mr. Robert Jones; $500,000 against Mr. Miller; and $500,000 against Mr. Wells. The Commission further directs Coaltrain, Mr. Peter Jones, and Mr. Sheehan to disgorge, jointly and severally, unjust profits, plus applicable interest, pursuant to section 309 of the FPA, in the amount of $4,121,894.The Commission directed the respondents to pay the civil penalties within 60 days, or else the Commission said it will commence an action in a United States district court for an order affirming the penalty.
Supreme Court rules on state energy incentives
Tuesday, April 19, 2016
The U.S. Supreme Court has released its ruling on a case affecting how states may provide incentives for electric power generation. In Hughes v. Talen Energy Marketing, LLC, the Court upheld a lower court's ruling invalidating a Maryland program to subsidize construction of new power plants. The ruling provides important insight into how the Court views the boundary between federal and state jurisdiction over energy matters.
The Hughes case involved a new Maryland program to encourage in-state generation capacity, and its relationship to federally blessed capacity market. Under the Federal Power Act, the Federal Energy Regulatory Commission has exclusive jurisdiction over wholesale sales of electricity in the interstate market, while States regulate retail electricity sales.
For years, Mid-Atlantic regional grid operator PJM Interconnection has held capacity auctions to identify need for new generation and compensate generators for development. PJM's auctions have been approved by the Federal Energy Regulatory Commission under the Federal Power Act. But due to concern that the PJM auction was failing to encourage development of sufficient new in-state generation, Maryland enacted its own regulatory program. Under that state program, Maryland held a competitive process to select a developer for a new power plant, and required load-serving entities to enter into a 20-year pricing contract (called a "contract for differences") with the developer. The developer would still sell its capacity to PJM, but would receive extra money under the state program to make up the difference between the PJM market price and the contract price.
But incumbent generators challenged the new Maryland program; a federal district court issued a declaratory judgment holding that Maryland's program improperly sets the rate the developer receives for interstate wholesale capacity sales to PJM. On appeal, the Fourth Circuit affirmed, finding that Maryland's program was preempted because it impermissibly conflicts with FERC policies. The case then came to the Supreme Court of the United States.
The Supreme Court's April 19, 2016 decision affirms the lower courts' rulings. The Court agreed with the Fourth Circuit's judgment "that Maryland's program sets an interstate wholesale rate, contravening the FPA's division of authority between state and federal regulators." In the majority opinion's words, "States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC's authority over interstate wholesale rates, as Maryland has done here."
The Hughes ruling sheds light on how the Court might view other state programs to incentivize new or clean generation. That said, the Court emphasized that its holding in Hughes is limited -- that it rejected Maryland's program "only because it disregards an interstate wholesale rate required by FERC." The Court explicitly said it would not address "the permissibility of various other measures States might employ to encourage development of new or clean generation," such as tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector.
The majority opinion concludes with a reminder that "[s]o long as a State does not condition payment of funds on capacity clearing the auction, the State's program would not suffer from the fatal defect that renders Maryland's program unacceptable." This suggests one potential path for permissible state incentives for electric power generation.
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| The Supreme Court of the United States. |
The Hughes case involved a new Maryland program to encourage in-state generation capacity, and its relationship to federally blessed capacity market. Under the Federal Power Act, the Federal Energy Regulatory Commission has exclusive jurisdiction over wholesale sales of electricity in the interstate market, while States regulate retail electricity sales.
For years, Mid-Atlantic regional grid operator PJM Interconnection has held capacity auctions to identify need for new generation and compensate generators for development. PJM's auctions have been approved by the Federal Energy Regulatory Commission under the Federal Power Act. But due to concern that the PJM auction was failing to encourage development of sufficient new in-state generation, Maryland enacted its own regulatory program. Under that state program, Maryland held a competitive process to select a developer for a new power plant, and required load-serving entities to enter into a 20-year pricing contract (called a "contract for differences") with the developer. The developer would still sell its capacity to PJM, but would receive extra money under the state program to make up the difference between the PJM market price and the contract price.
But incumbent generators challenged the new Maryland program; a federal district court issued a declaratory judgment holding that Maryland's program improperly sets the rate the developer receives for interstate wholesale capacity sales to PJM. On appeal, the Fourth Circuit affirmed, finding that Maryland's program was preempted because it impermissibly conflicts with FERC policies. The case then came to the Supreme Court of the United States.
The Supreme Court's April 19, 2016 decision affirms the lower courts' rulings. The Court agreed with the Fourth Circuit's judgment "that Maryland's program sets an interstate wholesale rate, contravening the FPA's division of authority between state and federal regulators." In the majority opinion's words, "States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC's authority over interstate wholesale rates, as Maryland has done here."
The Hughes ruling sheds light on how the Court might view other state programs to incentivize new or clean generation. That said, the Court emphasized that its holding in Hughes is limited -- that it rejected Maryland's program "only because it disregards an interstate wholesale rate required by FERC." The Court explicitly said it would not address "the permissibility of various other measures States might employ to encourage development of new or clean generation," such as tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector.
The majority opinion concludes with a reminder that "[s]o long as a State does not condition payment of funds on capacity clearing the auction, the State's program would not suffer from the fatal defect that renders Maryland's program unacceptable." This suggests one potential path for permissible state incentives for electric power generation.
Wind, solar lead new generation in Jan. 2016
Wednesday, March 9, 2016
Wind and solar projects accounted for all new electric power generation placed in service in the U.S. in January 2016, according to a report by federal energy regulators.
The Federal Energy Regulatory Commission's Office of Energy Projects releases a monthly Energy Infrastructure Update. These reports provide summary data and narrative highlights of energy infrastructure developments in the past month. Energy Infrastructure Update reports typically cover natural gas, nonfederal hydropower, electric generation, and electric transmission.
The report for January 2016 shows that all tracked electric generation placed in service that month was powered by either wind or solar. The report notes 5 wind projects placed in service in January 2016, with a total installed capacity of 468 megawatts. These projects are:
The January 2016 infrastructure update also notes that a battery storage project in Ohio has come online. Willey Battery Utility LLC’s Willey Battery Storage Project in Hamilton County, Ohio is described as providing supply-demand balancing service for the frequency regulation market in the PJM region. Under FERC Order No. 755, battery storage and other innovative technologies can be compensated for offering frequency regulation to the grid.
The Federal Energy Regulatory Commission's Office of Energy Projects releases a monthly Energy Infrastructure Update. These reports provide summary data and narrative highlights of energy infrastructure developments in the past month. Energy Infrastructure Update reports typically cover natural gas, nonfederal hydropower, electric generation, and electric transmission.
The report for January 2016 shows that all tracked electric generation placed in service that month was powered by either wind or solar. The report notes 5 wind projects placed in service in January 2016, with a total installed capacity of 468 megawatts. These projects are:
- MidAmerican Energy Co.’s 153.4 MW Adams Wind Project in Adams County, Iowa
- Fowler Ridge IV Wind Farm LLC’s 150 MW Amazon Wind Farm Expansion Project in Benton County, Indiana -- developed by Pattern Energy; power generated is sold to Amazon Web Services under long-term contract
- Los Vientos Windpower IV LLC’s 110 MW Los Vientos Windpower Phase 2 Expansion Project in Starr County, Texas -- power generated is sold to Bryan Texas Utilities, Garland Power and Light, and Greenville Electric Utility System under long-term contract
- Milo Wind Project LLC’s 50 MW Milo Wind Project in Roosevelt County, New Mexico -- power generated is sold to Southwestern Public Service Co. under long-term contract
- Patriot Renewables LLC’s 4.5 MW Beaver Ridge Hill Wind Project in Waldo County, Maine
The January 2016 infrastructure update also notes that a battery storage project in Ohio has come online. Willey Battery Utility LLC’s Willey Battery Storage Project in Hamilton County, Ohio is described as providing supply-demand balancing service for the frequency regulation market in the PJM region. Under FERC Order No. 755, battery storage and other innovative technologies can be compensated for offering frequency regulation to the grid.
FERC enforcement report cites screenshots, keylogger
Thursday, January 7, 2016
The Federal Energy Regulatory Commission has issued an Order to Show Cause and Notice of Proposed Penalty against Coaltrain Energy, L.P. and six individuals relating to alleged fraudulent transactions in PJM Interconnection L.L.C.'s energy markets. The Order, and a supporting Enforcement Staff Report, also includes allegations that Coaltrain made false and misleading statements and material omissions during the investigation. Notably, the report describes FERC Enforcement staff's discovery of troves of documents allegedly covered up by the respondents, including keystroke logs and computer screenshots recorded by the company's software. This e-discovery aspect gives FERC's Coaltrain enforcement case a unique character.
Fundamentally, the Coaltrain case presents FERC Enforcement staff's allegations that the respondents violated of the Commission’s Prohibition of Energy Market Manipulation, and that Coaltrain violated a Commission market behavior rule about accurate communications. At issue is an alleged scheme involving trades from June 15 until September 2, 2010. Traders allegedly engaged in a large volume of marginally profitable Up To Congestion (UTC) trades -- not to make money on those UTC trades, but with the intent to earn outsize payments from PJM's Marginal Loss Surplus Allocation (MLSA) program. FERC Enforcement staff's report describes its view of these trades as similar to those at issue in other recent enforcement cases, and different from normal arbitrage or "spread" trades.
The FERC Enforcement staff report in the Coaltrain case sheds light on another aspect of enforcement activity: how did Enforcement staff conduct its investigation of Coaltrain and the other respondents? In this case, the company’s computer security monitoring software, called Spector 360, played a key role. According to the report, Spector 360 "recorded every keystroke on employees’ computers (other than co-owners Peter Jones and Sheehan) and took screen shots of every employee monitor every twenty seconds all day long".
As staff noted in a footnote:
Not only does the FERC Enforcement staff report allege that this evidence exists, but moreover it alleges respondents made false and misleading statements about Spector 360 and the data it logged, including claims that they "forgot" about it. According to the report, the Spector 360 data included material responsive to data requests issued as part of the investigation - but Coaltrain allegedly only provided it to Enforcement after a former employee told Enforcement that the Spector 360 data existed:
Fundamentally, the Coaltrain case presents FERC Enforcement staff's allegations that the respondents violated of the Commission’s Prohibition of Energy Market Manipulation, and that Coaltrain violated a Commission market behavior rule about accurate communications. At issue is an alleged scheme involving trades from June 15 until September 2, 2010. Traders allegedly engaged in a large volume of marginally profitable Up To Congestion (UTC) trades -- not to make money on those UTC trades, but with the intent to earn outsize payments from PJM's Marginal Loss Surplus Allocation (MLSA) program. FERC Enforcement staff's report describes its view of these trades as similar to those at issue in other recent enforcement cases, and different from normal arbitrage or "spread" trades.
The FERC Enforcement staff report in the Coaltrain case sheds light on another aspect of enforcement activity: how did Enforcement staff conduct its investigation of Coaltrain and the other respondents? In this case, the company’s computer security monitoring software, called Spector 360, played a key role. According to the report, Spector 360 "recorded every keystroke on employees’ computers (other than co-owners Peter Jones and Sheehan) and took screen shots of every employee monitor every twenty seconds all day long".
As staff noted in a footnote:
A large portion of the evidence in this matter is derived from the documents and other materials recorded by Spector 360. While the keystroke text data is not much different from ordinary documents, the screen shots taken by Spector 360 are very different, and create a visual record of what Respondents were working on, what they were looking for, how they conducted their analyses, and what they actually saw—as if standing over their shoulders while they work. This evidence will be reproduced as images taken from the screen shots.Indeed, the Enforcement staff report includes a series of screenshots allegedly captured by Coaltrain's software. According to the report, the evidence captured by Spector 360 shows how the respondents developed, implemented, and communicated about their scheme.
Not only does the FERC Enforcement staff report allege that this evidence exists, but moreover it alleges respondents made false and misleading statements about Spector 360 and the data it logged, including claims that they "forgot" about it. According to the report, the Spector 360 data included material responsive to data requests issued as part of the investigation - but Coaltrain allegedly only provided it to Enforcement after a former employee told Enforcement that the Spector 360 data existed:
Enforcement sent several data requests to Coaltrain beginning in August 2010. In June 2012, Enforcement discovered from a former Coaltrain employee that Respondents had failed to produce an enormous set of documents that were highly relevant to the matters under investigation and responsive to Enforcement’s prior data requests. As it turned out, for nearly two years Respondents had failed to tell Enforcement that before, during, and after the summer of 2010, Coaltrain had deployed computer monitoring software, called Spector 360, that had recorded every keystroke (saved as text files) and made screenshots every twenty seconds of every monitor (saved as image files) on the work and home computers of every employee other than the co-owners, Peter Jones and Sheehan. Enforcement then asked Respondents to produce the missing materials. Respondents admitted that they still retained the data, but they at first refused to produce it by falsely denying that they could access the Spector 360 materials. Respondents belatedly produced the materials only after Enforcement arranged with the software manufacturer to give Respondents a new license at no cost. Once produced, the Spector 360 documents proved to be an enormous trove of responsive and relevant materials—about 10 gigabytes per employee during the summer of 2010.FERC has docketed the case as IN16-4-000. In its show cause order, the Commission directs Coaltrain and its co-owners to show cause why they should not be jointly and severally required to disgorge unjust profits of $4,121,894, and directs all Respondents to show cause why they should not be assessed civil penalties in the following amounts:
- Coaltrain: $26,000,000
- Peter Jones: $5,000,000
- Shawn Sheehan: $5,000,000
- Robert Jones: $1,000,000
- Jeff Miller: $500,000
- Jack Wells: $500,000
- Adam Hughes: $250,000
Chicago-area battery storage projects announced
Wednesday, November 12, 2014
Energy developer Renewable Energy Systems Americas Inc. has announced two grid-scale energy storage projects near Chicago.
Battery-based energy storage projects can offer benefits to the electricity grid by keeping the alternating current's frequency steady, and can do so at a lower cost than alternatives like ramping generators up and down. Thanks in part to new federal policies, battery projects capable of providing frequency regulation can now earn increased revenue for their owners.
This week RES Americas announced plans to pursue two energy storage projects in Illinois. The company describes itself as a specialist in third-party development and construction services for the renewable energy, transmission, and energy storage industries. It also builds renewable energy and storage projects that it owns itself.
In an apparent tribute to the Blues Brothers, its two newly announced projects will be named Jake and Elwood. The Elwood Energy Storage Center will be sited in West Chicago, while the Jake Energy Storage Center will be in Joliet. Beyond names and locations, the projects bear greater resemblance to each other than to the Blues Brothers. Both projects were acquired from Glidepath Power in September. Each will be interconnected to the Commonwealth Edison Co. electric grid, and will have an operational life expectancy of at least ten years. Each will use lithium iron phosphate batteries with a 19.8 megawatt capacity, capable of storing 7.8 megawatt-hours of energy.
RES Americas expects to begin construction on both projects this winter, and to complete them by August 2015. When complete, the battery projects will be able to provide real-time frequency regulation service to the PJM Interconnection LLC ancillary services market. Thanks to recent federal orders including FERC Order No. 784, faster and more accurate regulation resources -- like battery storage arrays -- should be compensated more highly. These policies both increase consumer demand and reduce developers' barriers to entry into battery-based energy storage projects.
Other battery projects are moving forward, based on values other than frequency regulation. Last month, Southern California Edison Company brought its Tehachapi Wind Energy Storage Project online. That $50 million project, the largest currently operating in North America, is capable of storing 32 megawatt-hours, deliverable as an 8 megawatt stream of energy for 4 hours. The Tehachapi system is designed to help even out the flow of power produced by wind farms, which is naturally variable and intermittent. Battery systems can also be designed to improve local reliability, support microgrids, or serve as non-transmission alternatives to building more utility wires.
For more information about battery energy storage projects, recent policies favoring energy storage and the opportunities they create, contact Todd Griset at Preti Flaherty at 207-791-3000.
Battery-based energy storage projects can offer benefits to the electricity grid by keeping the alternating current's frequency steady, and can do so at a lower cost than alternatives like ramping generators up and down. Thanks in part to new federal policies, battery projects capable of providing frequency regulation can now earn increased revenue for their owners.
This week RES Americas announced plans to pursue two energy storage projects in Illinois. The company describes itself as a specialist in third-party development and construction services for the renewable energy, transmission, and energy storage industries. It also builds renewable energy and storage projects that it owns itself.
In an apparent tribute to the Blues Brothers, its two newly announced projects will be named Jake and Elwood. The Elwood Energy Storage Center will be sited in West Chicago, while the Jake Energy Storage Center will be in Joliet. Beyond names and locations, the projects bear greater resemblance to each other than to the Blues Brothers. Both projects were acquired from Glidepath Power in September. Each will be interconnected to the Commonwealth Edison Co. electric grid, and will have an operational life expectancy of at least ten years. Each will use lithium iron phosphate batteries with a 19.8 megawatt capacity, capable of storing 7.8 megawatt-hours of energy.
RES Americas expects to begin construction on both projects this winter, and to complete them by August 2015. When complete, the battery projects will be able to provide real-time frequency regulation service to the PJM Interconnection LLC ancillary services market. Thanks to recent federal orders including FERC Order No. 784, faster and more accurate regulation resources -- like battery storage arrays -- should be compensated more highly. These policies both increase consumer demand and reduce developers' barriers to entry into battery-based energy storage projects.
Other battery projects are moving forward, based on values other than frequency regulation. Last month, Southern California Edison Company brought its Tehachapi Wind Energy Storage Project online. That $50 million project, the largest currently operating in North America, is capable of storing 32 megawatt-hours, deliverable as an 8 megawatt stream of energy for 4 hours. The Tehachapi system is designed to help even out the flow of power produced by wind farms, which is naturally variable and intermittent. Battery systems can also be designed to improve local reliability, support microgrids, or serve as non-transmission alternatives to building more utility wires.
For more information about battery energy storage projects, recent policies favoring energy storage and the opportunities they create, contact Todd Griset at Preti Flaherty at 207-791-3000.
FERC OKs sale of Dominion merchant power plants to Energy Capital Partners
Wednesday, August 21, 2013
Federal regulators approved yesterday the sale of three fossil fuel-fired power plants from energy company Dominion Resources Inc. to Energy Capital Partners LLC for $650 million. The order by the Federal Energy Regulatory Commission moves the deal closer to fruition. Is the transaction part of a trend in the U.S. energy industry?
Dominion is a major player in the U.S. energy business, serving customers in 15 states with its holdings in both the electricity and natural gas sectors. Dominion owns a portfolio of about 27,000 megawatts of electric generation and 6,400 miles of electric transmission lines, as well as vertically-integrated electric utilities like Dominion Virginia Power. Dominion also owns a large natural gas storage system as well as about 11,000 miles of natural gas transmission, gathering and storage pipelines.
Buyer Energy Capital Partners is a private equity firm focused on investing in North America's energy infrastructure. The firm has recently acquired other electric generation plants, including the 830-megawatt combined-cycle natural gas-fired Red Oak power plant in Sayreville, New Jersey, and the 847-megawatt Broad River simple cycle, natural gas-fired power plant in South Carolina.
Over the past several decades, Dominion added merchant power plants designed not to serve the load of its affiliated utilities. These plants produced electricity from coal, oil and other fossil fuels, and sold the power into regional wholesale markets such as those managed by ISO New England and mid-Atlantic grid operator PJM. But with tighter environmental regulations, and more competitive electricity markets thanks to low-cost natural gas, many New England coal and oil-fired power plants have a hard time succeding in the current markets. As an apparent result, in 2012 said it would sell or close its merchant coal-fired plants to realign its portfolio and improve return on invested capital and shareholder value, and sold the coal- and oil-fired Salem Harbor Power Station in Massachusetts.
In March 2013, Dominion announced a deal to sell its interests in three power plants to Energy Capital Partners. 1,528-megawatt Brayton Point Power Station, in Somerset, Massachusetts, is the largest remaining coal-fired power plant in New England. It has three coal-fired units and one unit capable of being firing oil or natural gas, as well as the coal-fired 1,158-megawatt Kincaid Power Station in Illinois.. Dominion also offered its stake in 1,424 megawatts of capacity at the Elwood Power Station outside Chicago, which is powered by nine 158-MW natural gas-fired combustion turbines.
The deal price announced was $650 million. At least one analyst has noted that after removing tax benefits, the deal implied an underlying price paid per kilowatt of capacity of just over $100, a price 30 times lower than the the cost of building a new coal-fired plant according to the U.S. Department of Energy.
The Federal Trade Commission approved the deal from an antitrust perspective under the Hart-Scott-Rodino Act in March 2013, so the Federal Energy Regulatory Commission approval today was among the final approvals needed.
Fossil fuel and electricity markets are experiencing changes, from tighter air emissions to the prospect of federal carbon regulation. Assuming the Dominion deal actually happens, does it signal a trend of utility divestiture of merchant fossil fuel-fired power plants? Will other utilities exit the merchant electricity generation business? Will we see increased transactional activity, as utilities sell their fossil fuel-fired plants? For how much longer will the buyers run these plants? In the case of the Salem station Dominion sold last year, buyer Footprint Power LLC is demolishing the old plant and redeveloping the site as a natural gas-fired power plant. Will Energy Capital Partners choose to keep Brayton Point operating in a market where margins are often tight? Or is this just the rationalization of Dominion's asset base, with no similar ripples throughout the sector?
Dominion is a major player in the U.S. energy business, serving customers in 15 states with its holdings in both the electricity and natural gas sectors. Dominion owns a portfolio of about 27,000 megawatts of electric generation and 6,400 miles of electric transmission lines, as well as vertically-integrated electric utilities like Dominion Virginia Power. Dominion also owns a large natural gas storage system as well as about 11,000 miles of natural gas transmission, gathering and storage pipelines.
Buyer Energy Capital Partners is a private equity firm focused on investing in North America's energy infrastructure. The firm has recently acquired other electric generation plants, including the 830-megawatt combined-cycle natural gas-fired Red Oak power plant in Sayreville, New Jersey, and the 847-megawatt Broad River simple cycle, natural gas-fired power plant in South Carolina.
Over the past several decades, Dominion added merchant power plants designed not to serve the load of its affiliated utilities. These plants produced electricity from coal, oil and other fossil fuels, and sold the power into regional wholesale markets such as those managed by ISO New England and mid-Atlantic grid operator PJM. But with tighter environmental regulations, and more competitive electricity markets thanks to low-cost natural gas, many New England coal and oil-fired power plants have a hard time succeding in the current markets. As an apparent result, in 2012 said it would sell or close its merchant coal-fired plants to realign its portfolio and improve return on invested capital and shareholder value, and sold the coal- and oil-fired Salem Harbor Power Station in Massachusetts.
In March 2013, Dominion announced a deal to sell its interests in three power plants to Energy Capital Partners. 1,528-megawatt Brayton Point Power Station, in Somerset, Massachusetts, is the largest remaining coal-fired power plant in New England. It has three coal-fired units and one unit capable of being firing oil or natural gas, as well as the coal-fired 1,158-megawatt Kincaid Power Station in Illinois.. Dominion also offered its stake in 1,424 megawatts of capacity at the Elwood Power Station outside Chicago, which is powered by nine 158-MW natural gas-fired combustion turbines.
The deal price announced was $650 million. At least one analyst has noted that after removing tax benefits, the deal implied an underlying price paid per kilowatt of capacity of just over $100, a price 30 times lower than the the cost of building a new coal-fired plant according to the U.S. Department of Energy.
The Federal Trade Commission approved the deal from an antitrust perspective under the Hart-Scott-Rodino Act in March 2013, so the Federal Energy Regulatory Commission approval today was among the final approvals needed.
Fossil fuel and electricity markets are experiencing changes, from tighter air emissions to the prospect of federal carbon regulation. Assuming the Dominion deal actually happens, does it signal a trend of utility divestiture of merchant fossil fuel-fired power plants? Will other utilities exit the merchant electricity generation business? Will we see increased transactional activity, as utilities sell their fossil fuel-fired plants? For how much longer will the buyers run these plants? In the case of the Salem station Dominion sold last year, buyer Footprint Power LLC is demolishing the old plant and redeveloping the site as a natural gas-fired power plant. Will Energy Capital Partners choose to keep Brayton Point operating in a market where margins are often tight? Or is this just the rationalization of Dominion's asset base, with no similar ripples throughout the sector?
Mid-Atlantic electric grid operator plans $2.4 billion in upgrades due to fossil-fuel plant retirements
Tuesday, March 12, 2013
The operator of the mid-Atlantic electric grid has announced a need for $2.4 billion in grid upgrades to keep the lights on in the coming years, as fossil-fueled generators shut down.
PJM Interconnection LLC is the regional transmission organization that manages wholesale electricity markets and the transmission grid in all or parts of 13 states and the District of Columbia, covering about 60 million people. In that role, PJM works with electric utilities and merchant generators to identify upgrades needed to maintain reliable electric service throughout its territory. In 2012, PJM authorized more than 750 electric transmission improvement projects with a total cost of more than $5 billion.
PJM released its annual regional transmission expansion plan on March 7. In that plan, PJM identified three major trends driving the need for further grid upgrades: upcoming power plant retirements, the rapid switch to natural gas, and the growth of wind power to meet states’ renewable energy requirements.
Of these, the large-scale retirement of fossil-fueled power plants may pose the greatest challenge. Power plant operators must inform PJM if they plan to close their plants, and are doing so in droves. PJM received 104 retirement requests between November 2011 and December 2012. In all, these requests signal intents to shutter 13,868 megawatts of generation. Retirement requests continue to roll in; in January 2013 alone, an additional 1,697 megawatts of generation filed notices of intents to retire. This tide of closures is driven largely by relatively low electricity prices and increased costs for coal- and oil-fired generation due to environmental and emissions regulations.
At the same time, 2012 brought a record amount of new generation to the PJM market, primarily fueled by natural gas. Meanwhile, the addition of new renewable resources to the grid - such as wind-powered generators - adds another layer of challenge, as these renewable projects are often located in relatively remote areas far from consumers in urban centers.
PJM must ensure enough power to keep its customers' lights on, a task that requires both having enough operating generators and the right amount of transmission to connect generators to customers. As a result, PJM has identified 130 projects needed to maintain reliability. These projects include new transmission lines, line rebuilds, equipment upgrades, and new and expanded substations, and substation additions.
Much of PJM's analysis is based on assumptions about which generation plants will close, which new generation plants will be built and come online, and how much consumer demand for electricity will grow. Will PJM's predictions come true? If so, consumers will bear the cost of PJM's identified grid fixes.
PJM Interconnection LLC is the regional transmission organization that manages wholesale electricity markets and the transmission grid in all or parts of 13 states and the District of Columbia, covering about 60 million people. In that role, PJM works with electric utilities and merchant generators to identify upgrades needed to maintain reliable electric service throughout its territory. In 2012, PJM authorized more than 750 electric transmission improvement projects with a total cost of more than $5 billion.
PJM released its annual regional transmission expansion plan on March 7. In that plan, PJM identified three major trends driving the need for further grid upgrades: upcoming power plant retirements, the rapid switch to natural gas, and the growth of wind power to meet states’ renewable energy requirements.
Of these, the large-scale retirement of fossil-fueled power plants may pose the greatest challenge. Power plant operators must inform PJM if they plan to close their plants, and are doing so in droves. PJM received 104 retirement requests between November 2011 and December 2012. In all, these requests signal intents to shutter 13,868 megawatts of generation. Retirement requests continue to roll in; in January 2013 alone, an additional 1,697 megawatts of generation filed notices of intents to retire. This tide of closures is driven largely by relatively low electricity prices and increased costs for coal- and oil-fired generation due to environmental and emissions regulations.
At the same time, 2012 brought a record amount of new generation to the PJM market, primarily fueled by natural gas. Meanwhile, the addition of new renewable resources to the grid - such as wind-powered generators - adds another layer of challenge, as these renewable projects are often located in relatively remote areas far from consumers in urban centers.
PJM must ensure enough power to keep its customers' lights on, a task that requires both having enough operating generators and the right amount of transmission to connect generators to customers. As a result, PJM has identified 130 projects needed to maintain reliability. These projects include new transmission lines, line rebuilds, equipment upgrades, and new and expanded substations, and substation additions.
Much of PJM's analysis is based on assumptions about which generation plants will close, which new generation plants will be built and come online, and how much consumer demand for electricity will grow. Will PJM's predictions come true? If so, consumers will bear the cost of PJM's identified grid fixes.
FERC releases report on demand response
Wednesday, November 9, 2011
Demand response is an innovative smart-grid approach to meeting society's electricity needs. As customer demands on electric grids increase, the generating resources needed to meet higher and higher peak demands are typically more expensive to run and have more adverse environmental impacts. In essence, demand response means covering electric load by having individuals or companies agree to temporarily cut back on electricity consumption in
response to peak demand conditions. When customers are willing to provide this service at a lower cost than generation, demand response can be a decentralized, crowd-sourced alternative to peaking power plants.
U.S. federal regulatory staff released a report this week assessing the nation's demand response and smart meter resources. The Federal Energy Regulatory Commission staff report is the sixth annual briefing since the enactment of the Energy Policy Act of 2005, which contained provisions promoting the development of demand response resources and markets.
The report notes that more and more customers have access to the kind of advanced meters that facilitate demand response participation. These smart meters can not only measure instantaneous electricity demand, but typically report back to a utility automatically using radio frequency communications. Since 2009, advanced meters have risen from 8.7% to a 13.4% share of all installed meters. The report suggests that the actual penetration rate of advanced meters may be even higher if it includes meters that are installed but whose advanced features have not yet been activated.
The report also notes that in 2010, the grid operators it surveyed had a total of 31,702 MW of demand response resource potential, or enough to cover about 7% of the total 2010 peak demand. Regional demand response capacities ranged from as low as 2.3% of peak load in the Electric Reliability Council of Texas to as high as 10.5% in the mid-Atlantic region's PJM Interconnection. The report noted that demand response resourcs "made significant contributions to balancing supply and demand during system emergencies" in 2011.
U.S. federal regulatory staff released a report this week assessing the nation's demand response and smart meter resources. The Federal Energy Regulatory Commission staff report is the sixth annual briefing since the enactment of the Energy Policy Act of 2005, which contained provisions promoting the development of demand response resources and markets.
The report notes that more and more customers have access to the kind of advanced meters that facilitate demand response participation. These smart meters can not only measure instantaneous electricity demand, but typically report back to a utility automatically using radio frequency communications. Since 2009, advanced meters have risen from 8.7% to a 13.4% share of all installed meters. The report suggests that the actual penetration rate of advanced meters may be even higher if it includes meters that are installed but whose advanced features have not yet been activated.
The report also notes that in 2010, the grid operators it surveyed had a total of 31,702 MW of demand response resource potential, or enough to cover about 7% of the total 2010 peak demand. Regional demand response capacities ranged from as low as 2.3% of peak load in the Electric Reliability Council of Texas to as high as 10.5% in the mid-Atlantic region's PJM Interconnection. The report noted that demand response resourcs "made significant contributions to balancing supply and demand during system emergencies" in 2011.
August 9, 2010 - new nuclear, flywheel storage, China energy efficiency crackdown
Monday, August 9, 2010
Nuclear power is a hot topic -- specifically the construction of new nuclear plants, something that most countries in the world have been slow to do in recent years. Now the United Kingdom says it anticipates building its first new nuclear plant in 2018, most likely on-site at existing nuclear facilities.
Meanwhile, in midcoast Maine, where the spent fuel from the decommissioned Maine Yankee nuclear plant has been stored on-site in Wiscasset, an editorial in the Brunswick Times Record calls for the nuclear waste to be shipped away. The editorial notes that citizens were told that waste would be removed by 2010 -- and with Yucca Mountain no longer viable as a storage site, area residents see no prospect of the waste being taken away as promised.
Just as oil and natural gas tank storage capacity can be used to smooth out swings in the availability and market price of fuel, energy storage can play a major role in ensuring power service while dampening price swings. Frequency regulation -- keeping the alternating current at 60 Hz, which essentially requires smoothing out the gap between supply and demand on an instantaneous basis -- is an important service that all electric grids need. As more and more intermittent generation resources come online, like wind, grids need more and more frequency regulation. Massive mechanical flywheels can provide this service. In today's news, Beacon Power Corporation has closed on a $43 million DOE-backstopped loan, completing the financing for the 20 MW flywheel energy storage plant Beacon is building in Stephentown, New York. The plant, which is under construction and on budget, is projected to cost $69 million, about 80% of which represents direct facility costs. The Federal Financing Bank, part of the U.S. Treasury, provided the $43 million loan. NYSERDA provided a $2 million grant, with Beacon putting up the remaining $26 million in cash, in-kind assets, and project costs. Beacon is also planning two more 20 MW flywheel projects: one in Glenville, NY, and one in the PJM Interconnection.
Supporting renewable and energy efficiency projects through grant funding programs is one way to improve a state's energy efficiency and emissions. In China, the world's largest energy consumer, the government is taking a different approach: ordering 2,087 industrial manufacturers rated as having low energy efficiency to close. Affected facilities, which produce steel, concrete, paper, coke, and forest products, will lose their emissions licenses next month. Just to be sure, the government will order utilities and banks to cease dealings with the sanctioned businesses. The government's stated motivations include slippage on its five-year plan energy efficiency plan, as China's economic recovery and booming construction industry drive energy consumption up.
Maine is moving forward with PACE financing -- but municipalities need to take a bit of action to open the door to residential energy efficiency in their communities.
Two quick links to Lewiston Sun Journal pieces about wind. First, a story by Naomi Schalit critical of the results of Governor Baldacci's pro-wind efforts. Second, a letter from my friend and Leadership Maine classmate Paul Williamson providing a counterpoint to last month's Jonathan Carter column critical of Maine mountaintop wind. More to follow on these stories soon.
Meanwhile, in midcoast Maine, where the spent fuel from the decommissioned Maine Yankee nuclear plant has been stored on-site in Wiscasset, an editorial in the Brunswick Times Record calls for the nuclear waste to be shipped away. The editorial notes that citizens were told that waste would be removed by 2010 -- and with Yucca Mountain no longer viable as a storage site, area residents see no prospect of the waste being taken away as promised.
Just as oil and natural gas tank storage capacity can be used to smooth out swings in the availability and market price of fuel, energy storage can play a major role in ensuring power service while dampening price swings. Frequency regulation -- keeping the alternating current at 60 Hz, which essentially requires smoothing out the gap between supply and demand on an instantaneous basis -- is an important service that all electric grids need. As more and more intermittent generation resources come online, like wind, grids need more and more frequency regulation. Massive mechanical flywheels can provide this service. In today's news, Beacon Power Corporation has closed on a $43 million DOE-backstopped loan, completing the financing for the 20 MW flywheel energy storage plant Beacon is building in Stephentown, New York. The plant, which is under construction and on budget, is projected to cost $69 million, about 80% of which represents direct facility costs. The Federal Financing Bank, part of the U.S. Treasury, provided the $43 million loan. NYSERDA provided a $2 million grant, with Beacon putting up the remaining $26 million in cash, in-kind assets, and project costs. Beacon is also planning two more 20 MW flywheel projects: one in Glenville, NY, and one in the PJM Interconnection.
Supporting renewable and energy efficiency projects through grant funding programs is one way to improve a state's energy efficiency and emissions. In China, the world's largest energy consumer, the government is taking a different approach: ordering 2,087 industrial manufacturers rated as having low energy efficiency to close. Affected facilities, which produce steel, concrete, paper, coke, and forest products, will lose their emissions licenses next month. Just to be sure, the government will order utilities and banks to cease dealings with the sanctioned businesses. The government's stated motivations include slippage on its five-year plan energy efficiency plan, as China's economic recovery and booming construction industry drive energy consumption up.
Maine is moving forward with PACE financing -- but municipalities need to take a bit of action to open the door to residential energy efficiency in their communities.
Two quick links to Lewiston Sun Journal pieces about wind. First, a story by Naomi Schalit critical of the results of Governor Baldacci's pro-wind efforts. Second, a letter from my friend and Leadership Maine classmate Paul Williamson providing a counterpoint to last month's Jonathan Carter column critical of Maine mountaintop wind. More to follow on these stories soon.
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