Page 1662 – RTO Insider

April 15, 2014

Federal Briefs

Powhatan Energy Fund, the firm that is waging an unusual public battle against the Federal Energy Regulatory Commission’s investigation of it for manipulative trading in PJM, is now also campaigning against the man chosen by the White House to be FERC’s new chairman. The nominee, Norman Bay, is a former federal prosecutor who has been FERC’s enforcement chief since mid-2009. (See PJM Trader Calls FERC on Manipulation Probe.)

The twin brothers who own Powhatan have a website devoted to combating FERC’s position on the transactions in question. Now that Bay has been tagged to lead the commission, “we’re out there actively trying to talk to senators and staffers about our story and spreading the word about the website and trying to get his nomination defeated,” an attorney for Powhatan said. The White House announced its nomination of Bay in January, but the Senate Energy and Natural Resources Committee has not scheduled a hearing on it yet.

More: Bloomberg Businessweek

CFTC to Give Public Power Assurance on Swaps Deals

The Commodity Futures Trading Commission will write a formal rule to fix a problem public power utilities have complained about since 2012. Soon after issuing a “no action” letter with assurances to public power in March, the CFTC said it would provide permanent assurance with a rule that effectively allows counterparties — natural gas companies, other utilities, power producers — to do “swaps” deals with public power without having to register as swaps dealers, as long as their aggregate swaps deals do not exceed $8 billion a year. The rule will put publicly owned utilities on the same basis as other energy companies. Current regulation sets a limit of $25 million a year, blocking traditional counterparties from doing these deals with public power.

More: Reuters

Gas Plants Led ’13 Capacity Additions; Solar 2nd

US Power Plant Capacity Additions 2013 (Source: EIA)

A little more than 13,500 MW of capacity was added to U.S. utility-scale supply in 2013, less than half the amount added in 2012, the Energy Information Administration reported. Natural gas plants accounted for slightly more than 50% of the 2013 additions, with solar contributing nearly 22%, coal making up 11% and wind at almost 8%. California led the additions, followed at a good distance by Texas, Florida and North Carolina.

Among new gas plants, additions came nearly equally from combustion turbine peakers and combined-cycle plants. Nearly 60% of the gas capacity added was in California. Two coal plants accounted for all the added coal capacity: one in Texas and the 571-MW Edwardsport integrated gasification combined-cycle plant in Indiana.

More: EIA

DOE Guarantee Program Reboots Soon, Moniz Says

The Department of Energy will open the door to new applications for renewable energy project loan guarantees during the second quarter of his year, Secretary Ernest Moniz said. Peter Davidson, head of the loan program, has suggested the revived loan guarantee program will focus on initiatives to help integrate renewables into the grid.

Under the low-emissions technology program, DOE recently finalized a guarantee for Georgia Power’s Vogtle nuclear project in Georgia and it is taking applications for coal- and petroleum-related carbon capture projects.

More: National Journal

Senate Finance Committee OKs Wind PTC Extension

The Senate Finance Committee approved a tax-extenders package that includes a two-year extension of the wind energy production tax credit, which expired at the end of 2013. The 2.3-cent/kWh credit, as before, would apply to utility-scale production for the first 10 years of operation.

More: Sustainable Manufacturer Network

‘Victory Bonds’ Proposed To Finance Clean Energy

Two Californians and 14 other Democrats have introduced a bill to create what they are calling Clean Energy Victory Bonds, an effort to put the World War II financing mechanism to work for renewable power and clean energy technology.

In the measure sponsored by Reps. Zoe Lofgren and Doris Matsui, Treasury bonds in denominations as low as $25 would “leverage $50 billion investment to provide up to $150 billion in public and private financing to fund the production of innovative energy technologies.”

More: PR Newswire

April 15, 2014

PJM-IMM Plan on FMUs Faces Generator Opposition

PJM and the Independent Market Monitor have reached an agreement on a rule change to reduce the number of Frequently Mitigated Units eligible for “adders,” but the proposal appears to face heavy opposition from generation owners.

Only units whose net revenues are not covering their avoidable cost rate (ACR) would be eligible for adders under the proposal presented to the Market Implementation Committee on first read last week.

The proposal represented a compromise by Market Monitor Joe Bowring, who had previously called for eliminating the adders altogether.

Had the proposal been in effect in 2013, it would have reduced the number of units receiving adders from 112 to only 28 — 23 of which are scheduled to retire. “Implementing the screen would result in a notable smaller number of FMUs” receiving the compensation, said PJM’s Tom Zadlo.

In polling among members of the generation-heavy MIC subgroup that has considered alternatives, however, 72% of voters said they opposed the proposal. A nearly identical percentage said they would favor either of two alternatives.

One of the proposals that received support in the poll would set the adders based on a plant’s run hours. The second would limit the compensation based on the gross Cost of New Entry for the unit’s Locational Deliverability Area.

FMUs were allowed adders in 2006 to ensure that they cover their avoidable, or going-forward, costs. The adders are graduated: Generators that are cost capped for 60% of their running hours receive an adder of either 10% of their cost-based offer or $20/MWh; those capped for 80% or more of their hours can receive $40/MWh. Similar rules apply to “associated units,” which share physical and economic characteristics to FMUs. The idea is to keep units in service that otherwise would not be economically available.

Bowring said the adders had become unnecessary for most units since the introduction of the capacity market in 2007 and changes to scarcity pricing rules in 2012. (See PJM Reconsiders Adders on Cost-Capped Generators.)

Despite the lack of support for the PJM-IMM proposal in the poll, PJM officials said they intend to bring their plan to an MIC vote next month.

“Although it was spun as a compromise proposal it’s only a compromise between PJM and the IMM, not other participants,” said Dave Pratzon, who represents generators. “I don’t think … that this is the best way to move forward.”

“This is a load-gen[eration] issue,” responded Dave Mabry, of the PJM Industrial Customer Coalition. “Nothing is going to get sector-weighted support.”

April 15, 2014

PJM Drops Interchange Ramp Plan

PJM has dropped a plan that would have allowed dispatchers to cut interchange ramp limits in order to reduce price volatility and uplift, the RTO told the Market Implementation Committee last week.

The proposal was received coolly by stakeholders when PJM officials floated it at the MIC’s March meeting. (See Ramp Limits Cause Stir at MIC.)

After internal discussions among PJM staff, the proposal “has been taken off the table,” PJM’s Lisa Morelli told the MIC last week.

Dispatchers will continue to have the ability to limit ramp to protect reliability and may use it more frequently in the future, Morelli said. But PJM will develop manual language to clarify the circumstances under which such action may be taken, she said.

At a Federal Energy Regulatory Commission technical conference April 1, PJM Executive Vice President for Operations Mike Kormos said PJM might consider requiring interchange transactions be scheduled two or three hours in advance so that operators can avoid having too much supply. Current interchange rules allow scheduling with only 15 minutes’ notice.

Kormos said unexpected imports contributed to PJM’s nearly $600 million in uplift costs in January. (See PJM May Offer Firm-Fuel Premium.)

April 15, 2014

PJM Seeks Better Data on Residential DR

Stakeholders will attempt to develop more accurate measurement and verification of residential demand response under a problem statement approved by the Market Implementation Committee last week.

PJM currently measures load reductions for much of its residential DR based on data that was compiled more than a decade ago in Maryland and New Jersey.

PJM’s Shira Horowitz said the data is no longer representative because of the growth of PJM’s footprint, changes in DR programs and increases in the energy efficiency of air conditioners and other appliances.

The old data were collected based on legacy “direct load control” (DLC) programs. Residential demand response now includes use of smart meters and programmable thermostats.

Some stakeholders questioned why PJM wants the review to include firm service level (FSL) and guaranteed load drop (GLD) programs in addition to DLC.

“I’m not seeing any concerns with the other two verifications,” said one stakeholder. “I’m struggling with why we want to expand this past DLC programs.”

Pete Langbein, of PJM, said the RTO wants to take a holistic approach to the issue.

“Residential [DR] is unique. We’re not dealing with a few thousand customers, we’re looking at millions,” he said. “From PJM’s standpoint, we don’t think we should limit this to DLC.”

Residential demand response supplies about 1,000 MW of capacity in PJM.

April 15, 2014

RTOs Weigh Role in GHG Compliance

Among the many questions about the pending EPA carbon rules on existing generation are how state implementation rules will mesh with regional compliance approaches and what role RTOs such as PJM will play.

PJM stands ready to help, Paul Sotkiewicz, PJM’s chief economist, told a Bipartisan Policy Center forum last week.

The economies of scale that RTOs have brought to unit dispatch, planning and other grid functions can also help reduce the costs of complying with the greenhouse gas rules, Sotkiewicz said.

“We can reflect the cost of environmental retrofits. It makes sense to piggyback on the existing infrastructure,” he said.

While it will be up to state officials to decide what the RTO role is and whether they want to participate, states that go it alone, he said, “are leaving money on the table.”

Two visions for how RTOs might take part were sketched out earlier this year. In January, PJM and other RTOs asked the EPA to allow states to meet the greenhouse gas rules through regional caps and to include a “safety valve” to maintain reliability.

ISO/RTO Council

The ISO/RTO Council (IRC) said that it usually doesn’t take policy positions on EPA regulations, but that it wanted to ensure EPA officials “recognize the relationship between proposed environmental rules, electric system reliability and economically efficient dispatch.”

The council’s seven-page proposal asks the EPA to allow states to adopt State Implementation Plans (SIPs) based on “a regional measurement mechanism for determining compliance.” The group also said the EPA’s regulations should include a process to mitigate reliability impacts of the regulations.

MISO Role Envisioned

In February, The Brattle Group and Great River Energy, a cooperative in MISO, proposed that RTOs build the carbon emission limits into their markets instead of making individual generators or states meet them.

Jeanne Fox, commissioner, New Jersey Board of Public Utilities

For the states that joined MISO or other regional operators, “It doesn’t seem like much of a stretch to add carbon management to that plate,” said Jon Brekke, vice president of Great River.

The proposal would have RTOs and ISOs translate EPA emission reduction limits into targets for their regional power markets. The reductions would be met by applying an RTO- or ISO-administered carbon price to generation and refunding the revenues to load serving entities based on consumption levels.

“This not a social cost of carbon … this is an economic signal,” said Brekke, who added that it would avoid stigma as a “tax” because the funds would go to LSEs rather than government.

Asked after the forum whether MISO was willing to take on the market-clearing role envisioned in the plan, Brekke responded: “We know that MISO is willing to facilitate a discussion that’s state-led.”

The idea of a regional solution is “getting traction,” he added. “Whether it’s our approach or another is secondary.”

RGGI Redux?

A top Delaware official, meanwhile, pitched the nine-state Regional Greenhouse Gas Initiative (RGGI) as a “plug-and-play” solution that other jurisdictions could adopt.

Collin O'Mara, secretary, Delaware Department of Natural Resources and Environmental Control — Collin O’Mara, secretary, Delaware Department of Natural Resources and Environmental Control

Carbon emissions in RGGI states have dropped by nearly 52% since 2005, thanks to energy efficiency and fuel switching — as well as the lackluster economy.

Current emission levels are 45% below RGGI’s 2013 cap, said Collin O’Mara, secretary of the Delaware Department of Natural Resources and Environmental Control. Participating in addition to Delaware are Connecticut, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont.

Money collected through RGGI is reinvested in energy efficiency and renewable energy giving every expenditure a multiplier effect twice or triple the investment he said. (New Jersey Gov. Chris Christie, however, used some of the revenues to balance his budget before pulling the state out of the program in 2011.)

Rather than calling it cap and trade, however, O’Mara suggested a less politically combustible name: “budget and invest.”

New Jersey’s Democratic-controlled legislature has tried on several occasions to pass legislation reversing Christie’s decision, but it has been defeated by vetoes. “I don’t see [rejoining RGGI] happening in the near future,” said New Jersey Board of Public Utilities Commissioner Jeanne Fox.

Seams

The PJM-MISO seam has vexed both regions for years, but when it comes to GHG compliance it could be a boon, Sotkiewicz said.

State implementation plans for the four states split between PJM and MISO — Michigan, Illinois, Indiana and Kentucky — could manage emission allowances across RTO borders, he said.

“Rather than seams being a problem it actually creates fungibility between different regional compliance programs,” Sotkiewicz said. “Rather than being a barrier, per se, it almost becomes an opportunity.”

April 15, 2014

PJM Plans Sept. 23 Grid Drill

PJM is planning a system-wide drill Sept. 23 to simulate simultaneous physical attacks on critical substations, cyber attacks and the loss of supervisory control and data acquisition (SCADA).

The drill will assess PJM’s and transmission operators’ readiness to respond to nation-state sponsored attacks.

It will incorporate lessons learned from the North American Electric Reliability Corp.’s GridEx II, an exercise that drew participation from 200 organizations, including PJM, in November. Some participants complained that the GridEx “injects” were introduced too rapidly and that communications between participants didn’t use real-world methods. (See Grid Exercise `Like a Disaster Movie.’)

“GridEx was a good exercise, but sometimes they used communication paths that were not traditional,” said LeRoy Bunyon, PJM manager of business continuity planning. He said the PJM drill will feature communication “not between planner and planner, but operator to real operator.”

According to a presentation to the Operating Committee last week, the drill will test the communication channels between PJM and transmission owners and their ability to respond to attacks by implementing emergency procedures.

Bunyon said PJM will participate using its Dispatcher Training Simulator and asked transmission owners to consider simulator use, as well, instead of using the drill as a tabletop exercise. He asked transmission owners to designate planners to help develop drill materials and conduct training.

April 15, 2014

Generator Survey Finds Fuel, Environmental Limits Curb Flexibility

Fuel procurement and environmental limitations are the top obstacles to increasing the flexibility of PJM’s generating fleet, according to survey results released last week.

About 83% of generator operators responding to the survey said they are operating to the limits of their plants’ flexibility. Of the remaining 17%, most cited fuel and emissions limits, with insufficient compensation “a distant third,” PJM said.

The survey was developed in response to what Adam Keech, manager of wholesale market operations, said was a decline in generation flexibility over the last decade.

PJM’s Eric Hsia told the Market Implementation Committee last week 20% of those who said their units were being offered as flexibly as possible reported their flexibility has decreased over time. Among the reasons cited were compensation rules that discourage investment in aging plants, lack of fuel, emission limits and “additional risk of tripping.”

PJM’s next step will be one-on-one meetings with companies to get more details. Hsia said some of the fuel issues are already being addressed by the Gas-Electric Senior Task Force.

April 15, 2014

Transmission Briefs

Bethlehem SPS (Source: Calpine and PJM Interconnection LLC)

Calpine announced a special protection scheme that will allow the outage of the Blooming Grove-Bushkill 230-kV line July 1 to accommodate construction of the Susquehanna-Roseland 500-kV line. According to a presentation to the Operating Committee Tuesday, the SPS also takes into account the expected retirement of the Portland coal units, scheduled for June 1.

The SPS calls for the trip of Unit 8 at Calpine’s Bethlehem station to relieve potential congestion from the loss of either of the two Steel City-Quarryville 230-kV lines. The SPS is expected to end in summer 2015 with the completion of the Susquehanna Roseland 500-kV line.

New Line Designations at Breinigsville

Breinigsville line designations (Source: PPL and PJM Interconnection LLC)

PPL announced new line designations coming out of its new Breinigsville substation. PPL plans to reuse the 5044 designation, currently used for the 500-kV Wescovsville-Alburtis line, for the Wescosville-Breinigsville 500-kV line. It would then christen the Breinigsville-Alburtis 500-kV line as 5058.

The new Breinigsville substation is designed to protect against excess voltage drop on 138-kV lines between Wescosville and Seigfried, excess transformer load at the Wescosville substation, and maximum allowable load drop if the Wescosville-Trexlertown #1 and #2 lines are lost.

The project is expected to be completed in May 2015.

April 15, 2014

FERC Rejects Con Ed Challenge on Tx Upgrade

The Federal Energy Regulatory Commission last week rejected Consolidated Edison Co.’s attempt to avoid paying for a major transmission upgrade in northern New Jersey but suggested it might order PJM to recalculate the company’s bill.

FERC’s ruling (ER14-972) approved PJM’s cost allocation for 111 baseline reliability upgrades included in the RTO’s Regional Transmission Expansion Plan (RTEP), including 17 eligible for regional cost allocation under Order 1000.

Only one of the projects, a $1.2 billion project upgrade to address thermal overloads and short circuit problems in the PSEG transmission zone outside New York City, was challenged. (See PJM: Con Ed Protest over PSEG Upgrade Groundless.)

PSEG Short Circuit Solution (Source: PJM Interconnection, LLC)

The project will convert Public Service Electric and Gas Co.’s Bergen-to-Linden 138 and 230 kV transmission line to 345 kV and add a second 345 kV transmission line between those points.

PJM’s cost allocation assigned $629 million of the cost to Con Edison under the Con Ed-PSEG “wheel,” in which PSEG takes 1,000 MW from Con Ed at the New York border and delivers it to Con Ed load in New York City.

Also challenging the cost allocation for the project is Linden VFT LLC, which owns a 315-MW merchant transmission facility that interconnects both PJM and NYISO. Linden said its RTEP bill would increase by $2.5 million annually as a result of the project.

FERC rejected Con Ed’s contention that it was not liable for the project because the reworked transmission grid would change its delivery point from that specified in its contract with PJM.

But the commission said it wanted more information on how PJM performed the distribution factor (DFAX) analysis that determined Con Ed’s share of the cost.

Con Ed says it was unfairly assessed almost 83% of the $762.6 million assigned through DFAX for its 1,000 MW wheel while PSEG was assessed only 7%, despite load of 11,000 MW. Con Ed said the cost distribution for the project is “grossly disproportionate to the relative loads” of the two companies.

“We cannot determine from this record whether the issues raised by Con Edison are generic issues related to the implementation of Solution-Based DFAX or are specific assumptions relating to this project,” the commission wrote.

Thus it ordered PJM to submit a compliance filing within 30 days “explaining and justifying the specific assumptions relating to the PSE&G Upgrade.”

April 15, 2014

PJM Considers New Rules on Defaults

Rules covering how PJM reallocates load when a load serving entity defaults can’t be found in the RTO’s manuals because, well, it doesn’t happen much.

But the collapse of two retail marketers after a spike in wholesale power prices during January’s arctic cold showed that load reallocation rules are needed, PJM officials told the Market Implementation Committee last week.

While there are mechanisms for collecting from other PJM members the $2 million in unpaid bills the two retailers left behind, what happens to the load the two companies had been serving is not clearly laid out in PJM’s rules.

Michelle Souder, of PJM’s member relations department, said PJM will add a new Section 3.2.4 to Manual 33: Administrative Services for the PJM Interconnection Agreement that covers this eventuality.

The new rules specify that PJM will notify the electric distribution companies delivering power to the retailer’s customer of the need to reallocate the load “as soon as such default is evident to PJM” and no later than the day the LSE is declared in default.

PJM will notify the EDCs by 10 a.m. the day after declaring an LSE in default whether the LSE has provided the funds to return to good standing. EDCs will not be required to reverse the load reallocation even if the LSE cures the default.

The manual language will be shared with the MRC later this month and presented to both groups for endorsement in May.

Bid Volume Limits

PJM is also considering a rule change that the RTO said would likely have reduced the size of the retailers’ January defaults.

PJM’s Hal Loomis outlined a proposal to prevent LSEs from entering day-ahead demand bids that are more than 20% and more than 10 MWs above their peak load forecast for the day.

“This would provide a way to keep inappropriately high demand bids from clearing,” including those resulting from data entry errors, said Loomis.

Had the proposal been in effect Jan. 7, at least 4% of demand bids would have been rejected, PJM said.

PJM will gauge the Credit Subcommittee’s interest in developing such a limit based on results of survey that closes today.