Page 1491 – RTO Insider

January 12, 2016

Court Next Stop for Developer, FERC Says

FERC said Friday it would not take up a renewable energy developer’s complaint about Connecticut’s procurement practices, clearing the company to return to court (EL16-11).

Allco Renewable Energy had asked FERC to begin an enforcement action under the Public Utility Regulatory Policies Act, saying it had been excluded by the state’s improper selection of a too-large, out-of-state wind project.

Allco filed the FERC complaint in November after its federal court suit against the state was dismissed because the company had not exhausted its administrative remedies. The Connecticut Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority last month asked FERC to dismiss the complaint. (See Connecticut Seeks Dismissal of PURPA Complaint.)

“Our decision not to initiate an enforcement action means that Allco may themselves bring an enforcement action against the Connecticut commission and DEEP in the appropriate court,” FERC wrote.

FERC said Friday it would not take up a renewable energy developer’s complaint about Connecticut’s procurement practices, clearing the company to return to court (EL16-11).

“Our decision not to initiate an enforcement action means that Allco may themselves bring an enforcement action against the Connecticut commission and DEEP in the appropriate court,” FERC wrote.

— William Opalka

January 12, 2016

MISO Seeks Bids on Duff-Coleman Project

By Amanda Durish Cook

MISO opened the floor on Friday to transmission developers’ bids for the congestion-relieving Duff-Rockport-Coleman 345-kV project in Southern Indiana and Kentucky. Developers have until July 6 to submit bids on the four-year construction project, and developer selection is planned to begin thereafter.

The call for proposals marks MISO’s first-ever competitively bid transmission expansion project under FERC Order 1000.

Forty-eight transmission developers are certified to submit bids. Non-qualified developers can submit applications for certification through Feb. 8.

6-Month Review

MISO has allowed for a roughly six-month review of developers’ proposals and plans to announce its choice before Dec. 30. The estimated in-service date is Jan. 1, 2021.

“Through extensive work with stakeholders to develop the competitive transmission process, MISO is ready to engage in a fair process to select a developer for Duff-Coleman,” Priti Patel, regional executive for MISO North, said in a statement. She said the proposals will be judged “in terms of certainty, specificity, risk mitigation and cost.”

MISO Staff Recommends 3 Economic Projects.)

The project has been designated by MISO as a market efficiency project. MISO’s Board of Directors approved it, along with more than 350 other transmission projects, as part of the 2015 Transmission Expansion Plan in December.

“This project completely mitigates the congestion on the MISO system around the Newtonville and Coleman areas and strengthens the 345-kV backbone in the region,” MISO wrote in its MTEP15 report. “In addition, the project fully addresses long-standing reliability issues around PJM’s Rockport station and obviates the need for the Rockport special protect scheme and operation guide that protects the stability of the grid.”

January 12, 2016

MISO Redesign Proceeds with New Committee

By Amanda Durish Cook

CARMEL, Ind. — MISO stakeholders Monday laid the foundation for the Resource Adequacy Subcommittee (RASC), hammering out a rough mission statement and management plan while determining it should report to the Advisory Committee.

The work took place during the first of a two-day work session of the Stakeholder Governance Working Group, which continues Tuesday.

Bill SeDoris, director of MISO integration for Northern Indiana Public Service Co., said he used pieces of the Supply Adequacy Working Group’s mission statement to outline the new panel’s role.

The RASC’s mission statement says the subcommittee will “provide input and policy guidance to MISO management and the Advisory Committee on all market and operational activities and processes to facilitate adequate planning resources within the MISO for the long-term planning horizon.”

The RASC will “coordinate its efforts with other MISO stakeholder groups, including all entities reporting to the Advisory Committee,” according to the draft mission statement.

Renuka Chatterjee, executive director of resource adequacy and transmission access planning, will serve as MISO liaison for the RASC.

“It’s certainly a [fresh] start,” said Michelle Bloodworth, MISO’s executive director of external affairs.

Next Stop, Steering Committee

Now it’s up to the Steering Committee to decide whether to approve the charter and management plan at its Jan. 27 meeting. If the subcommittee is sanctioned, a call for leadership and elections is planned for sometime in February with a first meeting slated for March that will review preliminary data stemming from the upcoming Planning Resource Auction.

Auction discussion will again make an appearance on the April agenda, with a special conference call planned to discuss results. The subcommittee will follow a monthly meeting schedule.

The new committee is part of stakeholder efforts to complete the RTO-wide redesign. (See MISO Stakeholders OK Redesign, Begin Implementation.)

Strategic Planning Continues

The Stakeholder Governance Working Group on Monday also continued work on setting priorities as part of MISO’s strategic planning process. The group is charged with putting together both a priority-setting process for other committees and its own list of priorities. The group picked up where discussions left off at last week’s Advisory Committee meeting.

MISO Vice President of Strategy and Business Development Wayne Schug identified five priorities on which the RTO wants to concentrate in 2016: the Clean Power Plan; improving coordination between the electric and gas systems; seams optimization and aligning border pricing; grid technology enhancement and storage; and infrastructure development. “We’ve gone from a system that’s had virtually zero wind to 15 GW of wind,” Schug said. The CPP could push wind’s contributions to 50 GW over the next few years, Schug said, and the grid has to be ready to deliver.

Gary Mathis, senior director of electric policy at Madison Gas and Electric, said he hoped stakeholders and RTO officials can align their priorities.

“It’d be hard to argue against striving for a great deal of consistency between MISO’s priorities and [priorities identified by the Advisory Committee],” Mathis said.

‘Middle Ground’

Stakeholders at the SGWG meeting favored what several called a “middle ground” approach where stakeholders can influence the RTO’s strategic priorities through recommendations for change.

Additionally, the Advisory Committee put out a request for stakeholders to brainstorm ideas on priorities and how they’re formed during a meeting on Jan. 8.

“We didn’t really talk about this in the Advisory Committee in December. There was never really any discussion on the priorities for the year,” said committee Chair Audrey Penner. She said the committee will have a bigger role in policy formation in 2016.

Dynegy Director of Regulatory Affairs Mark Volpe asked if the committee might move policy discussions and priority reviews to the mornings of its meetings, when MISO board members would be more likely to attend. Currently, board member attendance is heaviest in the mornings during “hot topic” discussions, and tapers off in the afternoons when committee priority discussions take place.

Schug told the Advisory Committee that MISO is eyeing an approach on priority setting where parent committees, such as the AC, have the power to delegate tasks based on priorities, but stakeholders would have preference when it comes to identifying issues that eventually become MISO priorities.

Redesign Discussion

Last week’s discussion also dipped into stakeholder redesign. Chris Plante of Wisconsin Public Service Corp. asked if parent entities should be the only ones allowed to identify priorities to the Advisory Committee or if task groups and working groups could also name primary issues. Tia Elliott, director of regulatory affairs at NRG Energy, said that it could be helpful if such groups take priorities to their parent entities before they’re put before the Advisory Committee.

“The value to me of this exercise is sifting through all of the various priorities and finding the most important ones,” said Kent Feliks, American Electric Power’s manager of regulatory and RTO policy.

Penner said prioritization of issues will continue to be a main theme for MISO, and the Advisory Committee is considering planning an off-site meeting around mid-February for stakeholders to weigh in on the strategic planning process.

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.