Page 1490 – RTO Insider

January 12, 2016

Vermont OKs Canadian Hydro Line

By William Opalka

The Vermont Public Service Board on Tuesday approved a 1,000-MW transmission line to bring Canadian hydropower into New England, completing state and federal review of a project that could begin construction this year.

The New England Clean Power Link, proposed in 2013 by a unit of the Blackstone Group, is scheduled to be in service in 2019.

“The NECPL will provide significant environmental, electrical and economic benefits for Vermont and the region, including diversifying the state and regional fuel supply, reducing greenhouse gas emissions, creating in-state jobs, producing millions of dollars in new state and local taxes and public good benefits, and potentially lowering electricity costs,” the order said (Docket # 8400).

Blackstone Group unit TDI New England began its open season last month and reported expressions of interest from seven potential customers on both sides of the border. (See Infrastructure Build-out Moves to Forefront in New England.)

The company’s project timeline calls for completion of an interconnection study and project financing, execution of transmission service agreements and the beginning of construction in 2016.

Ninety-eight miles of the cable would be buried under Lake Champlain, and most of its land-based route would be underground to Ludlow, Vt.

The order noted that the project “will not be without impacts.” It cites a large, above-ground station to convert direct current power to alternating current. Travelers on Vermont highways where the HVDC line will be buried will be inconvenienced during construction.

“However, we conclude that the project’s benefits are significant enough to outweigh any potential negative effects, thus promoting the general good of the state,” regulators said.

The U.S. Department of Energy approved the project last year. (See Energy Department OKs Canadian Hydro Line in New England.)

Competing Project

A competing project, the Northern Pass, would deliver 1,090 MW through New Hampshire and is also scheduled to deliver energy in 2019.

Its opponents say the speed in which the Clean Power Link has progressed through the approval process means it is likely to deliver energy first. That clouds the prospects for the New Hampshire project ever getting built, they say.

However, a spokeswoman for Northern Pass has said that project has an interconnection approval from ISO-NE, a confirmed supplier of energy in HydroQuebec and a commitment from Eversource Energy to buy some of the electric power.

Massachusetts Gov. Charlie Baker is pushing legislation that could allow the state’s suppliers to buy up to 1,200 MW of power in addition to the needs of neighboring states.

January 12, 2016

MISO Market Subcommittee Briefs

MISO told the Market Subcommittee it will agree to a FERC order requiring it to post day-ahead market results at least 30 minutes before the 2 p.m. Eastern Prevailing Time gas timely nomination deadline. (See FERC Orders MISO to Shift Electric Schedule.)

However, MISO’s Kevin Larson said the compliance filing will include a rehearing request asking that its day-ahead schedule not adjust for daylight saving time.

Prevailing time reflects the shifts between standard time and daylight time, when clocks move ahead by one hour between the second Sunday in March and the first Sunday in November.

“Our practice of using Eastern Standard Time dates back to 2006 because Indiana was an oddball state and didn’t use daylight savings,” Larson said.

A decade later, MISO says it can’t “quantify any benefits” in transitioning to daylight saving time and says the cost of the switch would be burdensome to market participants.

“Implementing semi-annual transitions to and from DST will result in significant impact and cost to MISO and our market participants,” MISO wrote in a presentation.

As proposed by MISO, the day-ahead clearing window will close at 10:30 a.m. with results published by 1:30 p.m. EPT.

It would maintain the 6 p.m. EPT Forward Reliability Assessment Commitment (FRAC) notification time and the one-hour FRAC rebid period. Because the RTO publishes FRAC results as available, it said the deadline has little impact on when market participants actually receive notification.

MISO to Begin SPP Settlement with $16 Million Payment

MISO is about to make a one-time, $16 million payment to SPP to cover excess flow charges over the past two years under the settlement the RTOs agreed to in October. (See SPP, MISO Reach Deal to End Transmission Dispute.)

Beginning in February, MISO will send SPP $1.33 million monthly to cover flows over 1,000 MW crossing MISO’s North-South interface. The monthly payments will continue until February 2017, when the monthly amounts will be based on prior year usage.

John Weissenborn, MISO’s director of market services, said a true-up between the payments and the actual north-south flows from February 2015 through the end of January will take place in June.

As an interim measure, MISO will collect the $1.33 million monthly from members through a miscellaneous charge based on market load ratio share (load and export schedule volumes).

MISO stakeholders are continuing settlement discussions to determine a final cost allocation mechanism (ER14-1736). “These miscellaneous charges will be used until cost allocation talks are finalized,” Weissenborn explained.

MSC Approves Charter, Management Plan

The Market Subcommittee approved without objection a charter nearly identical to last year’s. The committee also adopted its 2016 management plan, which lists the issues it expects to cover in its monthly meetings.

Chairman Kent Feliks described the plan as a “snapshot” of the group’s coming work, saying it would be subject to change. Among the issues included in the plan are an evaluation of the energy offer cap, implementing five-minute settlement calculations and coordinated transaction scheduling with PJM.

Demand Response Talks in Limbo

Stakeholders rejected a suggestion to table discussion of three initiatives regarding aggregation of demand response resources and lowering the 5-MW minimum participation threshold.

“The question was should they keep pushing the rock uphill… [The Demand Response Working Group] has been spinning their wheels on this for some time,” said Jeff Bladen, MISO’s executive director of market design.

Several stakeholders said the issues were still legitimate and deserved to be kept alive.

But with the working group slated for retirement under the RTO’s redesign, it is unclear when or where the issues will arise next.

Monitor Reports Quiet Fall Quarter

MISO’s fall quarter was defined by falling energy prices, said MISO Market Monitor David Patton of Potomac Economics in a quarterly report to the Market Subcommittee.

Patton reported a 40% reduction in natural gas prices at both the Chicago Hub and the Henry Hub, with the average price at less than $2.50/MMBtu during the quarter.

The average price of power in the footprint fell below $22/MWh in November. For the quarter, the real-time price was $24.96/MWh, 13% lower than the summer quarter and 27% lower in a year-over-year comparison.

“It wasn’t a particularly exciting quarter,” Patton said.

Patton also said his staff is still gathering information on the November Texas price spikes caused by congestion. (See MISO Monitor Auditing Tx Outages that Caused Price Spikes.)

The annual State of the Market Report, expected by April, will include an analysis of the effectiveness of extended locational marginal pricing (ELMP), Patton said.

— Amanda Durish Cook

January 12, 2016

PJM Planning Committee TEAC Briefs

VALLEY FORGE, Pa. — Transmission reliability projects of less than 200 kV will be exempt from competitive proposal windows under Operating Agreement changes approved by the Planning Committee last week.

Such projects are almost always assigned to incumbent transmission owners because the solutions involve upgrades to existing transmission facilities and are located within, and allocated to, a single transmission zone.

PJM said the change will allow its engineers to focus on projects more likely to result in a greenfield project open to competition.

If the threshold had been in place for the 2014 and 2015 windows, it would have exempted 534 flowgates, said PJM’s Sue Glatz. The exemption will not apply to market efficiency projects.

The new rule contains two caveats that would require projects under 200 kV to go through a proposal window. In essence, they would be scenarios in which one or more projects could eliminate multiple reliability violations. (See “Action Delayed on Voltage Threshold for Competitive Projects” in PJM Planning Committee Briefs.)

Competitive developers previously had expressed reservations about the new threshold.

Sharon Segner of LS Power opposed the change because it does not provide a “catch-all” at the end of the planning process to put the project out for bid if it is determined to involve regional cost allocation.

“We believe that Order 1000 clearly says if there is regional cost allocation associated with a project, it needs to be opened to the competition,” she said.

PJM Vice President of Planning Steve Herling said performing a second analysis would defeat the purpose of the new rule.

“The idea of literally getting to the end and having a solution to recommend … and then stopping to bid the project out on essentially cost issues is not where we want to go,” he said, adding that PJM is “hoping” the screens it has in place will capture such projects.

Segner responded, “Hope doesn’t give us that protection from a new entrant standpoint. … Hope isn’t enough in light of Order 1000.”

PJM to Send Five Market Efficiency Projects to Board

Five market efficiency projects, all in the ComEd zone, will be presented to the Board of Managers for its approval next month.

Four involve upgrading capacitors at the Brambleton, Ashburn, Shelhorn and Liberty substations. The other is an upgrade to the 345-kV Loretto-Wilton Center line.

PJM planners also will recommend that the board advance the Hanover Pike baseline project, designated to Baltimore Gas and Electric, from a completion date of 2021 to 2019. While it remains in the Regional Transmission Expansion Plan based on its original designation as a reliability project, PJM is studying whether it might also provide market efficiency benefits.

Segner opposed the acceleration and noted that Northeast Transmission Development, an LS Power company, had expressed its objection as well in a letter to PJM.

Northeast Transmission previously had proposed a Keysers Run project that she said also would solve the Hanover Pike issue at a savings of about $46 million. The Keysers Run project had been identified as meeting the threshold for approval as a market efficiency project, she said.

“We think this is incredibly inappropriate in the middle of the cycle to take a project with an in-service date of 2021 and pull the project into the market efficiency process,” she said.

Herling said the project would remain with BGE despite the change in its status.

“We’re struggling with taking a project away from a designated entity once it’s been awarded,” he said. “That’s really the crux of the matter.”

Proposal Window to Open by End of January

PJM expects to open the first Regional Transmission Expansion Plan window of 2016 in the next few weeks.

Regardless of previous registrations, interested members must register before the window opens. The registration will be good for the year.

PJM’s new up-front, non-refundable project fee will go into effect for this window.

There is no fee to assess any project less than $20 million. There is a $5,000 fee to study projects from $20 million to $100 million. Projects that cost more will be charged a $30,000 fee. (See “PJM Lowers Proposed Tx Project Study Fee” in PJM Planning Committee Briefs.)

Phase Angle Regulators Qualify for Transmission Rights

PJM has determined that phase angle regulator (PAR) technology is eligible for transmission injection rights under the Tariff. The Planning Committee endorsed a new section to Manual 14E: Merchant Transmission Specific Requirements making that clear.

PJM’s review was requested in November 2014 by PSEG Energy Resources and Trading. (See “PAR Transmission and Withdrawal Rights” in PJM Planning Committee Briefs.)

Projects will be subject to automatic control. The guidelines also recommend that the initial “step size” of a facility’s output not exceed 20 MW when transitioning from zero flow because of concerns that a larger step could jeopardize stability. PARs will be studied based on proposed interconnection location on a case-by-case basis to determine impacts.

Task Force will Create Design Standards for Competitive Projects

The Planning Committee approved a charter for the Designated Entity Standards Task Force, which will set minimum design requirements for competitively solicited facilities.

The task force grew out of a problem statement approved in July following a review of the RTO’s initial Order 1000 experiences.

The standards will apply to transmission lines, substations and system protection and control design and coordination.

The task is expected to take 12 to 24 months.

— Suzanne Herel

January 12, 2016

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — The Market Implementation Committee discussed two proposals that would delay the disclosure of financial transaction right ownership following an auction.

The effort to mask FTR ownership has been championed by DC Energy’s Bruce Bleiweis, who contends that FTR owners should be afforded the same confidentiality as PJM’s other market participants. Faced with significant opposition, led by Independent Market Monitor Joe Bowring, Bleiweis has amended his proposal over the past few months. (See “Compromise Offered on Masking FTR Ownership” in PJM Market Implementation Committee Briefs.)

The package he presented last week would allow PJM to post aggregate data following an auction, masked ownership data three to six months later and full disclosure after one year.

“This is a significant evolution from where we started,” he said. “What we’re headed toward is no commercial information available while an auction is ongoing.”

Jeff Whitehead of Direct Energy suggested Bleiweis consider releasing masked information on auction close. “I’m not saying it gets me to ‘yes,’ but it gets me closer,” he said.

The second package, presented by PJM, is similar but would remove the tiered release of information to make it consistent with how the RTO releases other data, said PJM’s Tim Horger.

After posting aggregate data at the close of an auction, PJM would disclose the full ownership information four months later.

“We’re kind of indifferent to any changes associated with this,” he said. “We’re fine with the status quo. If membership wants change, that’s OK too.”

The packages will be brought back for a first read next month.

Market Data Confidentiality Rule Change Gets First Reading

The issue of market data confidentiality returned to the committee after one item regarding individual generation outages was tweaked since last month.

A spirited discussion over what and when PJM may disclose publicly has been going on since a problem statement was presented in June. (See PJM Considering Release of Uplift, Outage Data.)

Current rules prohibit PJM from talking about certain information even after it’s been disclosed publicly, such as the nuclear plant outages posted to the Nuclear Regulatory Commission’s website. They also limit the data PJM may share with stakeholders about conditions surrounding certain weather events, closed loop interfaces and transmission planning.

Stakeholders have debated for months over how to provide PJM the ability to discuss situations such as generator outages while at the same time not jeopardizing a member’s competitive standing in the market.

The current rule allows PJM to release aggregated data of more than three market participants and requires that information released involve a geographic area no smaller than a transmission zone.

PJM is proposing six exceptions that would allow PJM to the release or discuss:

Information on individual generation outages involving an unusual operating condition on the transmission system such as a severe weather event;
The amount of demand response in an area no smaller than three ZIP codes (specific offers or suppliers would remain confidential);
The total amount of capacity offered and cleared, aggregated by transmission zone;
Uplift payments in an area no smaller than a transmission zone, and for no shorter a time period than one operating day;
Aggregated statistics related to the results of the three pivotal supplier test; and
Data made public by a PJM member or a state or federal regulator.

“The intent here is not to be doing a monthly posting of widespread data,” said PJM’s Tom Zadlo. “It’s just the ability to answer questions from stakeholders.”

Operating Parameter Terms to be Defined

Members approved an issue charge to define terms related to operating parameters and move them from the eMKT/Gateway User’s Guide to PJM manuals. There was one abstention.

The 12 terms, including soak time, start-up time and minimum run time, also will be the focus of a special MIC session set for 1 to 4 p.m. on Jan. 19.

The committee is fast-tracking the issue in hopes of having the changes in place for the June 1 implementation of Capacity Performance.

— Suzanne Herel

January 12, 2016

Company Briefs

Eversource Energy and National Grid have completed a three-state $483 million transmission project to serve southern New England.

The Interstate Reliability Project included station upgrades and the installation of a new 345-kV transmission line along 75 miles of existing rights of way in Connecticut, Massachusetts and Rhode Island. “The Interstate Reliability Project improves the efficiency of the grid by eliminating system bottlenecks and improving the flow of power within our region,” said David Boguslawski, vice president of transmission strategy and operations at Eversource.

More: Eversource and National Grid

Fuel Cells to Help Power Research Facility

FuelCell Energy has announced a deal to install a natural gas-powered fuel cell system capable of producing 5.6 MW at Pfizer’s Groton research facility.

The company expects the two fuel cell power plants to be in place and operating by summer. The system will provide electricity and steam for the 160-acre facility under a 20-year power purchase agreement.

FuelCell also said the system would operate in synch with Pfizer’s regular electricity purchases and will be able to provide power during any grid outages. The companies did not disclose the financial terms of the deal.

More: Hartford Courant (subscription required)

Austin Energy GM Calls for Independent Board to Run Utility

Larry Weis, who in his final weeks as Austin Energy’s general manager, says the municipal utility should be run primarily by an independent board and not the Austin City Council, calling the newly elected council “naïve” about utility issues and vulnerable to outside influences. He also called for increased base utility rates for residential customers.

Weis, who earns $315,000 as the city’s highest-paid employee, is leaving the country’s eighth-largest public electric utility later this month to run Seattle’s electric utility.

Weis had some advice for his replacement. “You can’t come here and just do anything you want,” said Weis, 61, who took the reins of Austin Energy in 2010. “You’ve got to play ball with the rest of the city. There are a lot of problems in getting things done that way.”

More: Austin American-Statesman

Southern Reports More Delays, Costs for Kemper Plant Start-up

Southern Co.’s troubled clean coal plant in Kemper County, Miss., is still running into problems, and the company said it might delay the scheduled start-up again. Southern estimated that the plant, the first of its kind in the U.S., would cost $2.8 billion when it was first announced. The price tag is now $6.5 billion.

The plant is designed to turn coal into gas, and capture the resulting carbon dioxide and sequester it in underground storage caverns. Repeated design changes, construction overruns and other cost increases have plagued the project. Southern, while not saying how much longer testing and reconfiguring would take, has acknowledged that each month’s delay costs it $43 million.

“While these tests have confirmed the design of these first-of-a-kind systems, we have also identified some modifications, rework and needed repairs that will be implemented and retested before these systems can be placed in service,” a Southern spokesperson said. “This is not unexpected for systems being commercialized for the first time.”

More: Bloomberg Business

Ameren Warns Dockside Customers Before Discharging Dam

Ameren Missouri opened spill gates at Bagnell Dam in central Missouri last week in order to accommodate flow as the U.S. Army Corps of Engineers released a large amount of rainwater stored 90 miles upstream at Truman Dam. The swollen Truman Reservoir has been building up rainwater since late December.

The water dispatch led Ameren Missouri to warn residents along the shores of the Lake of the Ozarks and the Osage River to shut power off to their docks and other waterside structures until the fluctuating water levels recede.

“We plan to have the spill gates open for up to two weeks,” said Warren Witt, director of Hydro Operations at Osage Energy Center. “When the Truman Dam waters are discharged, Osage Energy Center will remain on heavy generation for another several weeks as we draw down the lake to our annual spring level of 654 feet.”

More: Ameren Missouri

LS Power Announces Expansion of Virginia Energy Center

LS Power wants to expand a generating plant near Kings Dominion, a theme park in Virginia, by building two more combustion turbines to generate a combined 340 MW. Doswell Limited Partnership, which is controlled by LS Power, has applied for permission to construct the two turbines.

There already are four combined cycle turbines on the site generating 665 MW, as well as a simple cycle turbine with a capacity of 171 MW. The company believes there is market demand for more power in the area, especially gas-fired peaking capacity. “It’s driven by a lot of market moves such as coal plants retiring, the price of natural gas and consumers’ demand for power,” said Tony Hammond, asset manager for Doswell.

More: Richmond Times-Dispatch

Duke to Build 17-MW Solar Farm in Indiana

Duke Energy has announced plans to build a 17-MW solar facility on the grounds of a Navy base in Indiana. The 145-acre site at Naval Support Activity Crane, near Plainfield, will have about 76,000 solar panels, according to the company. When completed, it will be one of the largest solar facilities in Indiana.

The company has filed for permits from the Utility Regulatory Commission. The company will make the energy available to Duke Energy Indiana customers, including the naval base.

It would be Duke’s second solar farm on a military base. The company built a 13-MW solar farm at Marine base Camp Lejeune in North Carolina.

More: Inside Indiana Business

NRG Home CEO McBee Announces Departure

Amid an exodus of executives at NRG Energy, Steve McBee has departed as president and CEO of NRG Home, the company’s retail residential business unit.

The company did not give a reason for McBee’s departure. His exit comes about a month after NRG CEO David Crane stepped down amid a steep downturn of the company’s stock price. Robyn Beavers, founder and leader of a microgrid research and development organization within NRG called Station A Group, also left last month.

NRG Home is NRG’s residential retail division, which includes its solar energy business. McBee came to NRG in December 2014 from a D.C.-based strategic consulting business that he founded.

More: Bloomberg News; Greentech Media

ComEd Teams with Startup to Give Customers Energy Info

Commonwealth Edison has teamed up with a startup created at Northwestern University to provide customers a way to track and change their energy use. MeterGenius allows customers to go online and access their energy-use data collected by ComEd’s smart meters.

A pilot program allows 6,500 ComEd customers to use MeterGenius tools to earn rewards such as gift cards and appliances, and enter competitions to see who can reduce their energy use the most. MeterGenius was started by four Northwestern graduate students in 2013 and now is based in St. Louis.

More: The Daily Northwestern

FirstEnergy Conducting Study on Reopening Hatfield’s Ferry

FirstEnergy is studying whether to reopen a 1,710-MW coal-fired plant in southwestern Pennsylvania that it closed in 2013. The company mothballed the Hatfield’s Ferry plant in Greene County because of low wholesale prices and declining demand in the area, along with anticipated costs of bringing its coal-fired generators into environmental compliance.

The company says it is reconsidering the closure because of evolving market forces and changing regional capacity conditions. “We’re only evaluating whether this would be a feasible option down the road,” said Jennifer Young, FirstEnergy spokeswoman. Young said the company is looking at all options, including the possibility of shifting the plant to use natural gas instead of coal.

The status of a second coal-fired plant that was also shut down in 2013, the 370-MW Mitchell plant in nearby Washington County, is not currently being reconsidered.

More: Observer-Reporter

Exelon Signs Go up on Baltimore Tower

Workers have installed signs denoting a 20-story tower under construction at Harbor Point in Baltimore’s Inner Harbor to be the local headquarters of Exelon.

The tower, which will also have 100 apartment units, is being built on the grounds of the former Allied Signal Chemical Plant between Harbor East and Fells Point. Exelon committed to maintaining a local headquarters when it acquired Constellation Energy. The tower is slated to open later this year.

More: Baltimore Business Journal

January 12, 2016

IPPs Challenge Dominion on Proposed Va. Generator

By Rich Heidorn Jr.

Independent power producers are challenging Dominion Resources’ bid to build a 1,588-MW combined cycle plant in the first major test of a 2013 Virginia law requiring utilities to demonstrate that they have considered “third-party market alternatives” to self-build projects.

Dominion Virginia Power filed its request for a Certificate of Public Convenience and Necessity with the Virginia State Corporation Commission in July, saying its proposed $1.3 billion plant in Greensville County was cheaper than any of the alternatives submitted in response to its request for proposals to fill the increased power demands it expects by 2019 (PUE-2015-00075). Evidentiary hearings on the proposal are scheduled to begin today in Richmond.

In a joint filing to the SCC last week, the Electric Power Supply Association and the PJM Power Providers Group (P3) challenged the fairness of Dominion’s RFP and its evaluation of the competing bids. They said regulators should deny Dominion’s request and order a new “open, broad RFP subject to independent review.”

The groups said Dominion’s RFP “was not designed to elicit competitive bids” but to satisfy the legal requirements to justify its self-build proposal. While the company had been planning a 3×1 combined cycle plant since 2011, the November 2014 RFP, which sought baseload/intermediate generating resources in service by 2020, gave competitors only six weeks to submit bids. They also contended the RFP included “unnecessary and overly restrictive” specifications regarding contractual terms, fuel supply and the plant’s location.

Internal Review

In its application, Dominion’s said its self-build proposal and responses from seven other bidders were impartially evaluated by a Dominion team separate from the staffers developing the Greensville plant. The proposals were judged on price and non-price metrics, including “economic impact, fuel strategy, facility reliability, bidder financial strength and environmental risks.”

The company called the Greensville power station “the clear economic and operational choice” as the next required resource for its long-term needs, saying it would save customers $2.1 billion in net present value compared to purchases from the PJM wholesale market.

“It will support a continued balance of demand and supply resources, in addition to wholesale market purchases, and will serve as a prudent addition to the company’s generating fleet,” Dominion said.

If approved, the Greensville plant would be the third combined cycle plant built by Dominion in five years.

The company said it is projecting peak load growth of approximately 4,580 MW in the Dominion zone over the next 15 years, an average increase of 1.5%. PJM’s 2015 load forecast identified the zone as the fastest growing in the RTO because of its popularity as a site for energy-hungry data centers. (See Changes to PJM Load Forecast Cuts Benchmark Peaks.)

The plant would boost Dominion’s rate base. The company proposed a revenue requirement of $41.6 million per year based on a 10% return on equity. SCC staff said the requirement should be cut by $2.5 million based on an ROE of 9.25%.

EPSA and P3 said the SCC should require a neutral, third-party evaluation of bids because the utility has a conflict of interest.

“The notion that Dominion employees can impartially review the company’s own proposal simply because they were not on the ‘self-build team,’ along with the company’s conclusion that its option represents a net present value savings of $1.5 [billion] to $2.304 billion compared to the alternatives evaluated, are suspect at best,” the groups said. “There is nothing in [the company’s] testimony that gives us any idea of what the company actually did to evaluate alternatives.”

The company’s two proposals received scores of 4.52 and 4.54 on a 5-point scale, while the highest scoring of the seven competitive bids received only a 3.3 rating.

SCC Staff Noncommittal

The groups were also critical of the SCC staff, saying it “has not undertaken a critical analysis of Dominion’s conclusions regarding its analysis of market alternatives.”

Marc A. Tufaro, a principal utilities analyst in the commission’s Division of Energy Regulation, filed testimony Nov. 20 saying the Greensville plant “is expected to have the lowest total cost when dispatched in excess of a 20% capacity factor.”

Tufaro did challenge the company’s projected savings, saying its forecasts of fuel prices, market purchase prices and other factors were “extremely difficult to predict with a high degree of accuracy.”

Tufaro said whether Dominion adequately considered third-party market alternatives was “a difficult question to answer,” expressing no opinion.

“Should the commission determine that the company has adequately considered third-party market alternatives, staff is not opposed to the approval of a CPCN for Greensville.”

Tufaro said “no respondents or comments [were] filed by the public contesting” Dominion’s conclusion Greensville was a better option than any third-party alternatives. EPSA and P3 said Tufaro ignored testimony by a consultant to environmental groups who they said criticized “the limited scope” of Dominion’s RFP.

2013 Law

The Virginia General Assembly amended the state Electric Utility Regulation Act in February 2013 requiring that a “utility seeking approval to construct a generating facility shall demonstrate that it has considered and weighed alternative options, including third-party market alternatives, in its selection process.”

In October 2015, the SCC rejected Dominion’s proposed 20-MW Remington solar facility, ruling that the evidence submitted by the company — an analysis of North Carolina’s solar market — was insufficient because the resources the company considered were already committed.

The commission said a “serious and credible RFP process would certainly be relevant to whether a CPCN applicant has met the code’s requirement to consider and weigh third-party market alternatives in the company’s selection process; however, we do not need to rule herein that a formal RFP must always be performed in a CPCN case in order to fulfill the demonstration required by [the law] regarding alternative options, including third-party market alternatives. There may be other credible methods to meet the statute’s requirement.”

January 12, 2016January 29, 2024

MISO: Redispatch Key to CPP Compliance Through 2025

By Tom Kleckner

LITTLE ROCK, Ark. — MISO’s 15 states may be able to comply with the Clean Power Plan through 2025 by redispatching the RTO’s generation fleet, according to early modeling by RTO staff.

David Boyd, vice president of government and regulatory affairs, told officials of Arkansas’ Department of Environmental Quality and Public Service Commission on Jan. 5 that MISO has been conducting modeling exercises in three “discrete tranches.” The first analysis, due to be completed in February, was conducted to help the RTO understand how it might help its footprint reach compliance.

“It looks like we can be compliant as a region through 2025, primarily through dispatching energy,” Boyd said in discussing the preliminary results. “We believe we can use the new resources coming online and existing resources to reach compliance.”

Boyd told the joint stakeholder meeting that the study is based on a “viable trading scheme” within its region. He said MISO is also conducting individual state-by-state analyses and an evaluation of leakage’s effect on generation dispatch.

“As we look forward with state [renewable] standards, bringing more wind resources online, state energy efficiency programs … we’ll be all right,” Boyd said.

Boyd said more information is forthcoming at the Jan. 20 Planning Advisory Committee meeting. MISO staff told the PAC in December that a flexible compliance strategy that mixes generation resources and trading programs will lower compliance costs. (See MISO: Coal Retirements, Gas Prices, Flexibility Key to CPP Compliance Costs.)

Boyd told the group that changing MISO’s dispatch processes by incorporating carbon costs could “lead to an increase in the cost structure of electricity.”

The ADEQ and APSC — which are jointly developing the state’s response to the CPP — have been gathering comments and feedback. The state’s comments on the CPP are due to EPA by Jan. 21. Arkansas and other states face a Sept. 6 deadline to submit either an implementation plan or an extension request to EPA; states that don’t meet the deadline run the risk of having a federal implementation plan imposed.

ADEQ Director Becky Keogh reminded the group that Gov. Asa Hutchinson has directed them to find the least-cost compliance method. At the same time, Arkansas’ attorney general has joined the multistate litigation against the plan.

“Arkansas is continuing to pursue a dual-strategy approach that involves communications with other state agencies, the attorney general’s office and the governor’s office,” said Stuart Spencer, the ADEQ’s associate director of air quality. “While we still plan to enter comments, we’re mindful our attorney general has entered litigation.”

The stakeholders were joined by Sarah Adair, a senior policy associate with Duke University’s Nicholas Institute for Environmental Policy Solutions, who has been crisscrossing the country convening regional dialogues on the CPP. She described the pros and cons of the mass- and rate-based compliance approaches.

Several stakeholders noted the absence of a reliability safety valve in the federal implementation plan. “My understanding of how EPA would approach reliability would be to work with FERC on the federal plan” in the same way states are required to demonstrate they considered reliability in developing a state plan, Adair said.

“The EPA says in the final rule [it’s] not worried about reliability with a trading system,” she said. “With the allowances or credits, companies can always go out and buy more credits if they need to run a unit more.”

The flexibility of trading, which does not limit emissions from any particular unit, “inherently addresses the issue of reliability,” Adair said in an interview.

January 12, 2016

MISO Preparing a Place for Energy Storage in Tariff

By Amanda Durish Cook

CARMEL, Ind. — With one energy storage project under construction and several others being considered, MISO is beginning a look at rule changes needed to accommodate the emerging technology.

One fundamental question MISO will have to answer is whether storage will be considered generation or categorized as a transmission asset, MISO External Affairs Policy Advisor Jennifer Richardson said during a workshop at the Jan. 5 Market Subcommittee meeting.

“We’ve had kind of fits and starts with this issue … but as far as having a clear policy, well, that’s never happened,” Richardson said.

Last July, Indianapolis Power & Light began work on a 20-MW advanced battery, MISO’s first grid-scale storage array. The facility, located at the Harding Street Generation Station in Indianapolis, is expected to begin service in June. IPL’s parent, AES, has 116 MW of energy storage projects in operation and has 268 MW in construction or late-stage development globally.

MISO said it also has been approached by “several market participants who are considering battery storage options for the future.”

“I think what’s really noteworthy here is that there’s not a lot of precedent or cases here for MISO to determine whether this will be behind-the-meter or in-front-of-the-meter,” said Executive Director of Market Design Jeff Bladen, who added that the RTO wouldn’t encourage any method of energy storage over another.

MISO wrote short-term energy storage — such as batteries and flywheels, which can supply less than an hour of power — into its Tariff in 2009. Long-term resources such as pumped storage can provide energy, regulating and spinning reserves under the Tariff.

However, medium-term storage — battery and thermal storage that can provide hours of power — cannot serve as capacity, energy or contingency reserves under current rules.

“Medium-term storage is gaining a lot of interest,” said MISO Principal Advisor of Market Development and Analysis Yonghong Chen.

Chen said stakeholders need to discuss what sort of products MISO should provide. “Storage is a broad range of emerging technology … it can be complicated.”

MISO said CAISO, with 5,800 MW of storage in operation or development, is the most advanced region. ISO-NE, by contrast, has less than 1 MW of storage. PJM, which has about 200 MW of energy storage in operation, also has been considering rule changes. (See Treat Electric Storage Like Limited DR: PJM.)

“CAISO is certainly on one end of the spectrum and MISO may be somewhere in the middle. The issues that we’re looking for guidance on [are] really pretty vast,” Richardson said.

FERC also has been updating its rules to open ancillary services markets to more competition from storage. (See FERC Clarifies Energy Storage Rule.)

Josh Pack, manager of energy technologies at Vectren, said projects proposed by market participants can shape policy. “There are emerging business models and new market entrants helping to figure this out,” he said.

Wind on the Wires Executive Director Beth Soholt said policy should consider how independent power producers or utilities will be compensated. “It comes down to one question: ‘What do I get paid for?’” she said.

MISO is asking for a first round of written feedback on the issues raised in the workshop by Jan. 22.

Bladen said MISO plans to review the responses at the Feb. 2 MSC meeting. Tasks relating to policy formation may be delegated to either the MSC or Planning Advisory Committee, officials said.

January 12, 2016

Exelon Calls FirstEnergy PPA ‘Grossly Lopsided,’ Says it Can Offer a Better Deal

By Ted Caddell and Suzanne Herel

Exelon, which is seeking subsidies for its Illinois nuclear plants, has joined the opposition to FirstEnergy’s attempts to win guaranteed payments for its Ohio power plants. And it says it has a better offer.

In a filing with the Public Utilities Commission of Ohio, Exelon said regulators should reject FirstEnergy’s “grossly lopsided” power purchase agreement, proposing a competitive bidding process to supply the 3,000 MW for which FirstEnergy is seeking guaranteed rates (the combined value of FirstEnergy’s W.H. Sammis coal plant and its Davis-Besse nuclear station).

Exelon Director of Regulatory and Government Affairs Lael Campbell said the company would submit an offer providing “well over $2 billion in savings to Ohio families and businesses” compared to FirstEnergy’s proposed PPA.

“Today we are taking the unprecedented step of committing to offer into that competitive process at a price level that will guarantee billions in savings so that no one can misunderstand the gravity of the harm that would occur to Ohio customers if the commission approved” the FirstEnergy PPA, he said. “We are putting our money where our mouth is.”

The specifics of Exelon’s offer were redacted, but Campbell said it would be an eight-year fixed price for energy and capacity of about 3,000 MW that would come from “100% zero carbon resources” — nuclear, hydro, wind and solar facilities in PJM.

Exelon spokesman Paul Elsberg said there have been no further communications with PUCO regarding the offer.

FirstEnergy spokesman Doug Colafella said the Exelon offer ignores one of the fundamentals of the FirstEnergy offer — a way to secure power from in-state generators and the almost 1,000 jobs of those who work at the Sammis and Davis-Besse plants.

Exelon, he said, has “no plants in Ohio, no jobs in Ohio.”

AEP PPA

PUCO also is considering a settlement calling for eight years of guaranteed rates for some of American Electric Power’s plants. Exelon said time constraints prevented it from making a similar offer in that case.

“Exelon requested additional time to file testimony in the AEP case, but the motion was not granted,” Elsberg wrote in an email. “The arguments made by Exelon against the First Energy proposal apply equally to the AEP proposal.”

Last week, PUCO ruled that the Sierra Club, IGS Energy and Direct Energy must submit to questioning to explain why they are supporting the AEP proposal.

PJM Urged to Oppose PPAs

On Jan. 6, the PJM Power Providers Group (P3) and the Electric Power Supply Association sent a letter to the PJM Board of Managers urging the RTO to actively oppose the AEP and FirstEnergy PPAs, contending they would undermine PJM’s competitive electricity market.

Last month, PJM submitted testimony to PUCO, saying the PPAs needed changes to preserve competition and the state’s ability to attract merchant generation. PJM has said it plans to issue a market analysis of the PPAs this spring, but that may be after the commission renders a judgment. (See PJM Seeks Changes to AEP, FirstEnergy PPAs.)

P3 and EPSA said the RTO’s actions were too little, too late.

“In testimony recently submitted to the PUCO long after the cases were underway and the dangers known, PJM indicated that PJM did not take a position on these nefarious efforts to undermine PJM’s markets,” they wrote. “Rather than advising the PUCO on the devastating impacts to the market in the short and long term, PJM instead sent a message that these subsidies would somehow be acceptable if certain conditions were attached.”

The groups said that the RTO is leaving the commission to evaluate the proposals “in a vacuum.”

“PJM should not be afraid to say when a program being considered at the state level directly undermines the wholesale market,” it said. “One would expect that the Ohio commission, while reserving the opportunity to disagree, would welcome the input of PJM on the full ramifications of what has been proposed.”

The groups said the reliability and competitive prices provided by PJM “will evaporate if the market is corrupted by state actions that subsidize uneconomic units.”

PJM declined to comment on the letter.

Pablo Vegas, president and CEO of Ohio Power Co. (AEP Ohio), responded to the letter with his own to PJM, saying P3 and EPSA were wrong to accuse the company “of undermining the very markets AEP Ohio has long sought to support and improve.”

“AEP Ohio has carefully worked to confine the proceedings before the PUCO … to matters of retail rate recovery,” he said.

He noted that PJM historically has refrained from “intruding upon retail ratemaking proceedings — or attempting to influence retail policies,” and urged it not to deviate from that precedent.

In a Jan. 7 order, PUCO denied PJM’s request to be a late intervenor in the AEP case but invited the RTO to submit a friend of the court brief to outline its concerns and make recommendations.

Exelon’s Campbell said FirstEnergy was a champion of the competitive process until now. “Ironically, FirstEnergy led the drive to competition and up until this proceeding took positions before this commission and other agencies and public officials which embraced competition and retail choice,” Campbell testified. “FirstEnergy was right then; it is wrong today.”

Exelon Seeks Relief for Ill. Nukes

While it is opposing FirstEnergy’s PPAs in Ohio, Exelon is seeking relief for its nuclear generators in Illinois. The company has requested that Illinois expand its clean energy subsidies to include nuclear power alongside wind and solar energy.

A bill backed by Exelon stalled in the Illinois legislature last year. Those critical of the Exelon subsidies have called them a nuclear “bailout” and said they would cost ratepayers around $300 million annually in surcharges.

In November, Exelon announced it has delayed for a year a decision on whether to mothball its Clinton reactor. (See Exelon Defers Clinton Closure; MISO Hints at Changes.)

January 12, 2016

FERC: Spy Software Provides Evidence of UTC Scam

By Michael Brooks

An energy trading company’s use of employee-monitoring software provided FERC investigators with evidence documenting its strategy of making riskless up-to-congestion transactions to collect line-loss credits from PJM, officials said last week.

FERC last week issued a show cause order demanding more than $42 million from Coaltrain Energy (IN16-4).

The commission used email and instant messages in lodging similar allegations against Powhatan Energy Fund and City Power Marketing. FERC’s Office of Enforcement found an additional source of evidence in their investigation of Coaltrain — the company’s use of Spector 360, software that logs users’ every keystroke and automatically takes screenshots every 20 seconds.

The commission said Enforcement staff was tipped off to the software’s existence by a former Coaltrain employee in June 2012, almost two years after it had begun its investigation into the company. Coaltrain employees initially claimed they had forgotten about the software when Enforcement made its original data requests and repeatedly delayed releasing the logs when asked for them, FERC said.

When Enforcement finally gained access to the Spector 360 logs, they received a voluminous amount of information — about 10 GB per employee — detailing the company’s actions in the summer of 2010, including emails, instant messages, Internet search and browsing history and, perhaps most important, internal logs of every single trade the company made over that time period.

A Familiar Story

Prior to June 2010, Coaltrain specialized in UTC trading, correctly predicting the changes in spreads between PJM’s real-time and day-ahead markets. This “spread strategy” involved complex analyses of transmission constraints and the impacts on LMPs. The company was very successful at these legitimate trades, FERC noted, earning profits of $12.8 million in 2008 and $18.7 million in 2010.

Coaltrain changed its trading strategy once it learned it could make more money from PJM’s marginal loss surplus allocation (MLSA) program, which refunds a portion of transmission loss charges to companies who contribute to the fixed costs of the grid. (See FERC: PJM Entitled to Recoup Line-Loss Credits.)

The company “discovered that they could profit from MLSA payments alone if UTC price spreads could be minimized or avoided entirely,” FERC said. Coaltrain devised a new “OCL strategy” — “over-collected losses” being its internal term for MLSA.

The allegations are similar to those against Powhatan and City Power. In fact, FERC said, when PJM released a report on June 1, 2010, showing how much in MLSA it had paid to companies, the Spector 360 logs show that Coaltrain co-owner Peter Jones sent City Power founder Stephen Tsingas an instant message congratulating him on collecting nearly $16 million in credits.

A few days later, Coaltrain employees began searching PJM’s website and Google for more information on MLSA, the Spector 360 logs show.

From June 15 to Sept. 10, 2010, Coaltrain traded 4.61 million MWh, losing more than $96,000 on the UTC price spreads and $3.83 million in transaction costs. However, it collected $8.05 million in MLSA payments, resulting in a profit of about $4.12 million.

“In contrast to the spread strategy that involved a complicated analysis using congestion-based constraints, the OCL strategy did not rely on constraints at all,” FERC said. “While there is voluminous evidence showing that [Coaltrain’s] strategy was designed not to profit from price spreads but instead to capture MLSA, a contemporaneous comment from [Adam] Hughes — who designed the software tools [the traders] used to carry out their scheme — sums it up: ‘create application to find deals for loss credits.’”

Severe Penalties

FERC is seeking $38.25 million in civil penalties from Coaltrain, its two owners and four employees, along with the $4.12 million in profits.

Enforcement staff said that it is seeking severe penalties because Coaltrain lied to them about the information it had logged using Spector 360. In comparison, the commission has assessed $29.8 million in penalties against Powhatan and $15 million against City Power.

“Coaltrain misrepresented material facts about relevant documents in an effort to hide them from Enforcement and made false and misleading statements concerning those documents as well as the availability of their witnesses to testify,” FERC said.

Coaltrain issued a statement Tuesday insisting it “was always responsive” to FERC’s information requests.

“The existence of computer monitoring software was disclosed to FERC and its staff in filings at the commission in 2009, which is before the investigation even began. When asked for the materials, Coaltrain cooperated with its former vendor to obtain a new license and provide the information requested. Suggestions that there was any delay in responding to FERC are erroneous and uninformed by the facts,” the company said. “Coaltrain is eager to cooperate with FERC to resolve this matter and has cooperated at every step of the process.”

FERC noted that Coaltrain’s owners had terminated an employee in their previous company, Energy Endeavors, based on the information received through the software about his activities.

In 2009, Jones and fellow owner Shawn Sheehan discovered that employee Moussa Kourouma was attempting to form his own energy trading business, in violation of a non-compete clause in his employment contract. The owners were able to use Spector 360 to track Kourouma’s activity down to his bank transactions.

Based on this information, they were able to protest Kourouma’s filing for market-based rate authority for his new company to trade in PJM. FERC said that in a confidential affidavit attached to the protest, Sheehan said the information came from “a commercially available software program for monitoring employee use.”

“The company regularly used Spector 360, and any claims that they ‘forgot’ about it are false,” FERC said.

The commission issued a Notice of Alleged Violation in September. (See FERC Charges Third Firm with UTC Scam in PJM.) Coaltrain has until Feb. 6 to respond to the Order to Show Cause.