Page 1679 – RTO Insider

December 23, 2013

FERC to Look Over PJM’s, MISO’s Shoulders at Joint Talks

Market to Market Payments: $Millions (Source: Northern Indiana Public Service Company) — (Source: Northern Indiana Public Service Company)

WASHINGTON — PJM and MISO will need to add a few more chairs for their next Joint and Common Market meeting.

Impatient over the pace of progress, the Federal Energy Regulatory Commission said last week it will begin having FERC staff monitor JCM meetings focused on eliminating barriers to the coordination of energy and capacity across the RTOs’ seam.

“Staff’s participation in this process will aid the Commission in monitoring the RTOs’ progress” in meeting the schedule they set out in a work plan filed Sept. 26, the commission said in an order (AD12-16).

The commission wants “to make sure [PJM and MISO] stay on track,” acting Chair Cheryl LaFleur said after the meeting.

Asked what the commission might do if staff reports insufficient progress, LaFleur responded: “We would be in a position to take a more aggressive step.”

Action on NIPSCO Complaint Deferred

In a related matter, the commission deferred action on Northern Indiana Public Service Co.’s (NIPSCO) complaint (EL13-88) over the PJM-MISO Joint Operating Agreement interregional transmission planning process. NIPSCO noted that the JOA had failed to produce a single cross-border transmission upgrade after nine years.

The commission said it was delaying a ruling pending related proceedings in other dockets.

One of those cases was docket AD12-16, which the commission initiated in June 2012 to solicit comment on how the RTOs could eliminate barriers to the delivery of generation capacity between them.

Work Plan Filed

The September 26 filing by PJM and MISO followed an unusual commission meeting June 20 in which representatives of the RTOs and state regulators made presentations on why the process has bogged down.

MISO complained that PJM was improperly limiting generators in its footprint from full participation in the PJM capacity market. PJM officials denied the claim, noting that MISO generators more than doubled the volume of cleared capacity in this year’s auction compared with 2012.

Several commissioners voiced frustration at that meeting and indicated the commission would take a more active role in the process. (See FERC Likely to Increase Pressure on PJM-MISO Joint Market Talks.)

The RTOs told the commission in the September filing that a survey of PJM and MISO stakeholders had identified data exchange and transparency; transmission and generation outage coordination and day-ahead market coordination as their highest priorities. Capacity deliverability modeling, capacity product definition and transmission allocation for cross-border capacity transactions were identified as the lowest priorities.

Deliverability Analyses

To address the conflict over cross-border capacity sales, the RTOs said they will conduct a series of deliverability analyses that increase the number of resources considered with each iteration. The schedule said the fact finding will be complete by March 31, 2014 and that any proposed changes that meet a cost-benefit analysis will be developed by fall 2014. (See PJM and MISO: Best of Frenemies)

The RTOs also said they were pursuing initiatives to address their higher priority issues and considering modifications to the JOA regarding participant funded transmission upgrades and auction revenue rights. Already, the RTOs said, they have improved the coordination of their generation interconnection and transmission service request queues.

The commission Thursday created a new docket (AD14-3) to oversee “the broadened scope of issues” identified by the RTOs.

NIPSCO Complaint

NIPSCO Territory Map Showing Transmission Lines (Source: Northern Indiana Public Service Company)

Caught in the middle of the PJM/MISO seam issues is NIPSCO, a MISO member whose territory is located between two PJM transmission zones, Commonwealth Edison to the west and AEP to the east.

NIPSCO asked for changes to the JOA’s interregional planning process in September, filing a section 206 complaint that alleged the JOA process had failed to address seams issues. It also filed protests to the MISO (ER13-1943) and PJM (ER13-1944) Order 1000 interregional compliance filings, saying the RTOs’ submissions do not comply with the commission directive.

Because of those failures, NIPSCO said it was being charged “unjust and and unreasonable” congestion costs. Congestion on MISO market-to-market (M2M) constraints totaled $367 million last year 2012, according to the MISO State of the Market report.

NIPSCO suggested six structural changes, including changes to transmission planning schedules and common metrics for valuing cross-border “market efficiency” projects. (See NIPSCO’s Prescription for PJM-MISO Seams Issues.)

“No cross border projects have been approved despite the presence of significant M2M costs, significant congestion, significant and ongoing operational impacts on NIPSCO’s system (including the need for operating guides to protect NIPSCO’s equipment and customers), and despite forecasts that the picture is only going to get worse,” NIPSCO wrote. “…The time for active Commission intervention is now.”

The commission rejected the RTOs’ request that it dismiss the section 206 complaint but said it was “premature” to rule on it pending further commission action on the Order 1000 filings, the capacity delivery efforts within the JOA and Docket No. EL13-75 (relating to MISO-PJM JOA market-to-market issues).

Commissioner Philip Moeller issued a concurring opinion, saying NIPSCO’s complaint “should be a high priority” when the commission rules on the MISO-PJM Order 1000 interregional compliance filings.

“It’s something I hope we can continue to stay focused on,” Moeller said in comments during the meeting, “because there’s a lot of money at stake.”

December 22, 2013

NIPSCO’s Prescription for PJM-MISO Seams Issues

In its complaint against PJM and MISO (EL13-88), the Northern Indiana Public Service Co. proposed the following changes:

The MISO-PJM cross-border planning process should run concurrently with the MISO Transmission Expansion Plan (MTEP) and PJM Regional Transmission Expansion Plan (RTEP) planning cycles, rather than after those regional planning cycles. NIPSCO proposes a schedule to have the interregional planning process run concurrently with the regional planning process.
There should be consistency between the PJM and MISO planning analysis. While the RTOs have regional differences, both entities should be consistent in their application of reliability criteria and modeling assumptions.
MISO and PJM should have a common set of criteria for the approval of cross-border market efficiency projects. The current and proposed changes to the JOA do not streamline the process but instead add delays, complications, and further administrative hurdles.
The criteria for approval of a cross-border market efficiency project should be amended to address all known benefits including, more specifically, avoidance of future market-to-market payments made to reallocate short-term transmission capacity in the real-time operation of the system.
MISO and PJM should be required to have a process for joint planning and cost allocation of lower voltage and lower cost upgrades for cross-border projects.
MISO and PJM must improve the processes within the JOA with respect to new generator interconnections and generation retirements.

December 22, 2013

Entergy Joins MISO; Largest RTO by Area

MISO began running the nation’s biggest Regional Transmission Organization by geography with the integration last week of Entergy’s transmission system and those of six smaller transmission owners.

The addition of territory in Arkansas, Mississippi, Louisiana and southeastern Texas gives the RTO control of transmission in 15 states from Canada to the Gulf of Mexico. MISO’s transmission system grew by nearly one-third (to 65,787 miles), while it added more than 30,000 MW of generation capacity, to almost 197,000 MW. MISO’s 900,000 square miles makes it the nation’s largest RTO by area.

In addition to Entergy’s six operating companies, the new MISO South region includes Cleco Corp.; Lafayette Utilities System; Louisiana Energy and Power Authority; NRG Energy’s Louisiana Generating; South Mississippi Electric Power Association and East Texas Electric Cooperative.

Generation, Load Diversity

PJM - MISO Comparison (Sources: PJM Interconnection, LLC & MISO) — (Sources: PJM Interconnection, LLC & MISO)

The MISO South “cutover,” which was completed Dec. 18, provides more diversity for MISO, with summer peaking regions in the south offsetting winter peaking areas in the north.

It also provides the Midwest easier access to natural gas and nuclear generation in the south, reducing the RTO’s dependence on coal, from 51% of capacity to 46%. A recent survey of MISO market participants projects a capacity shortage of 7,500 to 8,500 MW in 2016. (See MISO to PJM: We Need Capacity)

In theory, the transition also will make it easier for Midwest wind generators to move power to the south. But the lack of renewable portfolio standards in the region means wind power will have to compete on price alone.

Savings for Entergy

Entergy said the access to MISO’s market and the RTO’s economies of scale and transmission cost allocation will save its consumers $1.4 billion in the first decade. It also is expected to help Entergy escape a U.S. Justice Department inquiry into complaints by independent power companies, who have complained about what they called Entergy’s anti-competitive behavior for more than a decade.

ITC Merger Cancelled

Although the MISO integration was completed as expected, Entergy was forced to cancel its plan to sell its transmission system to ITC Holdings Corp. The $1.78 billion deal, announced two years ago, was scotched after the Mississippi Public Service Commission ruled Dec. 10 that the transaction was not in the public interest. The regulators said they feared state ratepayers’ costs would increase by $300 million over 30 years.

Entergy shareholders would have controlled about 51% of ITC after the transaction.

Power Trading

With the completion of the integration, MISO started reporting prices for trading hubs in Arkansas, Louisiana and Texas.

December 17, 2013

Don Miller, Long-Time PJM Rep, Retires from FE

Don Miller, an engineer whose career wove in and out of PJM since the late 1980s, attended his last PJM meetings last week.

FirstEnergy Corp.’s RTO policy manager, Miller retires effective Friday after 30 years at FE and its predecessor, General Public Utilities. He will be replaced by Jim Benchek.

Miller, 60, first worked on PJM activities in the late 1980s when he was doing transmission planning for GPU. He returned several years ago as part of FE’s FERC and RTO support team, serving on several PJM committees.

In between he helped smooth ATSI’s integration into PJM, helped FE prepare for the mandatory reliability standards authorized by Congress in the 2005 Energy Policy Act and participated in various projects related to industry restructuring.

Several of his former FE colleagues now work at PJM, including Andy Ott, Steve Herling and Jeff Bastian.

Miller said the basic PJM stakeholder process hasn’t changed much over the years. “We have always had equity issues, with a lot of spirited discussion among participating companies,” he said in an interview last week. “It’s the same now except there’s a lot more companies involved.”

He rarely spoke publicly at meetings. “My philosophy,” he said, “was to work on issues behind the scenes.”

Miller, who lives in Lancaster County, Pa., plans to remain there after retiring. He’s looking forward to spending more time hunting, fishing, traveling, visiting family and doing volunteer work through his church with his wife of 35 years.

“You want to spend as much time as you can in the go-go stage” of retirement, he said. “The longer you work the less time you have.”

December 17, 2013

Federal Briefs

The Marcellus shale formation in Pennsylvania and West Virginia will account for 18% of U.S. natural gas production this month, the Energy Information Administration reported. “Production growth in the region has driven down the forward price of natural gas at the Columbia Gas Transmission Appalachia hub below Louisiana’s Henry Hub price, the benchmark for natural gas throughout North America.” EIA said. “Natural gas pipeline expansion projects are expected to add at least 3.5 Bcf/d of takeaway capacity to the New York/New Jersey and Mid-Atlantic markets by 2015.”

More: EIA

High Court Seems to Lean Toward EPA Rule

U.S. Supreme Court West Facade (Source: Wikimedia Commons)

In oral arguments Dec. 10, most Supreme Court justices appeared sympathetic to at least some of the Environmental Protection Agency’s Cross-State Air Pollution Rule, which was thrown out in 2012 by an appeals court after attack by coal-state interests and others. The rule gets to a long-running fight between Eastern states with air-quality problems and Midwestern states whose coal-plant emissions the Easterners blame for a good deal of the trouble.

Challengers say EPA went beyond its authority and improperly designed the program, which limits sulfur dioxide and nitrogen oxide emissions from upwind states and allows trading of emission allowances. A high-court decision is expected by June.

A number of the downwind states, including Maryland and Delaware, have at the same time petitioned EPA to require coal states’ emission reductions under a different Clean Air Act regime (See PJM States Face Off on Pollution as Court Hearings Open).

More: The Washington Post; Reuters

Mercury Rule Gets Marathon Argument

Photo of the Meade and Prettyman Courthouse (Source: DC Circuit) — Meade and Prettyman Courthouse (Source: DC Circuit)

Arguments lasted an exceptional four hours at the U.S. Court of Appeals for the D.C. Circuit Dec. 10 as the Environmental Protection Agency defended its Mercury and Air Toxics Standard, which some states and coal interests have challenged as unjustified and overreaching in its requirements for coal-fired power plants.

On the same day that the Supreme Court heard the Cross-State Air Pollution Rule case, the D.C. Circuit asked detailed questions of both sides about the MATS rule. An environmental-group attorney saw reason to believe the judges would uphold EPA’s regulation, but an industry attorney thought the court was likely to find the agency vulnerable on at least some provisions.

More: Reuters

EPA De-emphasizing Enforcement; Focusing on Technology for Prevention

The Environmental Protection Agency plans to focus more on prevention and less on inspections and enforcement through 2018. “Next Generation Compliance” will use technology to keep a real-time eye on discharges and to have industry report electronically. The agency’s focus is on action “that makes the biggest difference,” an official said.

More: Greenwire

December 17, 2013

No Reliability Problems Seen for Winter

PJM’s assessment for the 2013-14 winter months identified no reliability issues, officials told the Operating Committee last week.

The annual assessment concluded the RTO has sufficient installed capacity to meet reserve requirements at the forecasted winter peak (about 136,000 MW) and that off-cost generation redispatch and switching will be sufficient to prevent thermal and voltage violations.

The assessment included a 50/50 peak load study — which assumes weather at average peak-day conditions — and an analysis of reactive transfer limits.

December 17, 2013

Grid Exercise `Like a Disaster Movie’

Last month’s GridEX II security drill was a valuable test of PJM’s emergency response procedures but lacked in realism, according to a briefing to the Operating Committee last week.

PJM’s Don Wallin said the North American Electric Reliability Corp. tried to stress the capabilities of the 200 organizations that participated in the Nov. 13-14 drill by giving them multiple simultaneous “injects.”

The scenarios included:

Denial of service attacks against shared service websites such as OATI;
Malware – similar to that which hobbled Saudi Aramco in a 2012 attack – that that exfiltrated sensitive information and locked corporate desktops and laptops;
Physical attacks against transmission and generation; and
Snipers firing at first responders.

The exercise was meant to simulate nation-state sponsored attacks against the grid. But Wallin said those who took part thought the volume of simultaneous injects undercut the verisimilitude.

“We don’t want this to be a Bruce Willis movie,” he said. Because the injects were compressed in such a short time, “it really took away from the realism and turned it into a disaster movie.”

More than 200 organizations, including 35 PJM member companies took part. Among those involved from PJM were the dispatch training team, corporate incident response team, cyber security incident response team, physical security incident response team and crisis communications.

Also involved were the FBI, Department of Homeland Security and the Electricity Sector Information Sharing and Analysis Center (ES-ISAC).

In addition to recommending the staggering of “injects,” participants said the drill should have used real-world communications channels.

GridEx III will be conducted in 2015. PJM plans a joint exercise with transmission owners in 2014.

December 17, 2013

DR at Home: EmPOWER Maryland

Some are in it for the money. Others say they are motivated by environmental reasons. “For my children … for their children and their grandchildren. For the future and the planet,” says one customer.

These are among the multi-ethnic group of customers, and their very cute kids, featured in testimonials for Pepco’s Energy Wise program.

Energy Wise is Pepco’s contribution to the EmPOWER Maryland initiative, created by the legislature with a goal of reducing energy consumption by 15% below 2007 levels by 2015.

The Maryland Public Service Commission’s Walter Hall and Pepco’s Gloria Godson worked doggedly to ensure PJM’s new rules on demand response would not ruin such “mass market” programs. As a result of their efforts, PJM’s new requirement for 30-minute dispatch exempts residential customers who cannot respond so quickly.

Results to Date

Three utilities and one cooperative run demand response programs under EmPOWER Maryland. In 2012, the utilities for the first time exceeded their annual savings forecasts, doing so by more than one-third. Still, they were only at 41% of their energy reduction and 51% of the demand reduction goals for 2015.

Much of the reductions to date have resulted from the lackluster economy, moderate temperatures and distributed generation. With direct load control programs beginning to reach saturation levels, officials said they will need contributions from combined heat and power and dynamic pricing to reach their goals.

The state, which spent $729 million on the program through 2012, approved an additional $95 million in funding last month. The funding comes largely from customer surcharges and capacity market revenues. The state expects to collect more than $57 million in capacity revenues for delivery year 2014/15 and $66.5 million for DY 2015/16.

Pepco’s Program

Pepco’s program includes three options for “cycling” air conditioners or heat pumps during PJM emergencies between June and October.

During an emergency, or “conservation period,” the air conditioner fan continues to circulate air but the compressor operations are reduced. Under the 50% option, the compressor operates half of the time it did in the hour prior to the conservation period, allowing temperatures to rise 1 to 3 degrees. It pays $40 a year.

There are also 75% cycling ($60/yr.) and 100% cycling ($80/yr.) options. The 100% option, which shuts down the compressor for the entire emergency, can result in temperatures rising up to 7 degrees and is not recommended for consumers with cardiac or respiratory conditions. Each program includes a one-time “installation credit” or signing bonus equal to the annual payment.

Pepco contributed about one-fifth of the state’s economic and emergency DR.

Baltimore Gas & Electric Co. runs the biggest program in Maryland, responsible for three-quarters of the state’s economic DR and 63% of emergency.

BGE’s Peak Rewards offers an air conditioning program similar to Pepco’s but with bigger savings ($50/$75/$100). BGE also offers a 100% hot water heater cycling program which pays $25 per year. It also conducted 63,000 home energy checkups in 2012.

Maryland represents nearly one–third of the 2,200 MWs enrolled in economic DR programs in PJM — more than any other state — but ranks behind Pennsylvania and Ohio in the emergency program with 15% of the 7,346 total. The top six states are responsible for more than 80% of the reductions in each of the programs.

December 17, 2013

Manual Changes

The Operating Committee last week endorsed changes to Manuals 3A and 13 while the Market Implementation Committee endorsed revisions to Manual 28.

Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA)

Reason for Changes: General update.

Impacts: Updates contact information; definitions; adds model validation and benchmark tests in response to FERC audit finding 13.

Manual 13: Emergency Procedures

Reason for Changes: 2014 Day Ahead Scheduling Reserve Requirement; Updates to terms, procedures.

Impact: Sets Load Forecast Error and Forced Outage Rate effective Jan. 1. References to interruptible load for reliability (ILR), no longer a valid term, are removed. Revised order of emergency procedures so that curtailment of non-essential plant and building load is curtailed as step 6, prior to issuing a manual load dump warning (step 7) and voltage reduction (step 8).

Manual 28: Operating Agreement Accounting

Reason for Changes: Section 5 – ER13-2413; Section 6 – Docket #ER14-297.

Impact: Changes section 6.3 to increase penalties for resources that fail to provide assigned amounts of Tier 2 Synchronized Reserve. Changes section 5.2.6 to clarify the requirements that must be satisfied in order for wind resources to be eligible to receive Lost Opportunity Cost (LOC) credits.

December 17, 2013

PJM to OK Only 1 of 17 Congestion Relief Proposals

PJM will likely approve only one of 17 congestion relief transmission proposals submitted in September, saying most failed to provide sufficient benefits or targeted problems that were already addressed.

Five of the projects were rejected because the congestion developers targeted had been addressed by other transmission projects or generation, PJM told the Transmission Expansion Advisory Committee in a briefing last week. Another nine projects failed to clear the 1.25 benefit-to-cost ratio.

Only three projects passed the cost-effectiveness screen. Because they all address congestion on the Hunterstown 230/115 kV transformer only one project — FirstEnergy’s proposed $8 million upgrade in the MetEd zone — is likely to be approved. Two proposals by Northeast Transmission Development (LS Power) were more expensive and had lower benefit-to-cost ratios, even under sensitivity analyses assuming a $1/mmBtu increase in natural gas prices and a 2% increase in load.

Wasted Time

It was a disappointing beginning for those who had hoped the Federal Energy Regulatory Commission’s Order 1000 would unleash competition in transmission development. Six developers and utilities submitted proposals ranging from $200,000 to $64 million, many of them targeting congestion in AP South and the Cleveland interface.

“A tremendous amount of time was spent on [these proposals] with no result,” said one stakeholder.

“PJM needs to educate stakeholders about how we calculate these values,” PJM’s Tim Horger told the Transmission Expansion Advisory Committee last week, citing one of the “lessons learned” from PJM’s first competitive window for “market efficiency” projects. “They’re not getting the same results we’re getting.”

“I’ll take the fault in that,” he added. After PJM conducts its training next year, he said, developers are “not going to spend a month developing a proposal that’s getting thrown out.”

Evaluating the proposals also consumed substantial PJM staff and computing time. Each proposal took 30 to 40 hours of computing time to evaluate, according to Vice President of Planning Steve Herling.

Cleveland Congestion Clears

PJM told the TEAC in June that the Cleveland Interface – the location of three proposed projects – was projected to have $15.5 million in annual congestion costs in 2017, growing to $38.3 million by 2023.

But Horger told the TEAC that the updated Regional Transmission Expansion Plan (RTEP) model showed “there’s no more congestion … or minimal congestion” in the area. “The model is constantly changing” due to new generation and transmission reliability projects, Horger explained.

Jung Suh, of Noble Americas Energy Solutions, noted that a $62 million FirstEnergy project rejected by PJM included a static VAR compensator. “Maybe you’re missing out on an opportunity to reduce reactive costs,” he said.

“That’s certainly something we could look at,” responded PJM’s Paul McGlynn, general manager for system planning.

Auction Revenue Rights

Dominion Virginia Power’s $24.6 million proposal to address constraints at AP South was rejected because it reduced Auction Revenue Rights (ARRs) more than it did Locational Marginal Prices – thus resulting in negative benefit-cost ratios.

“There was no information provided along with the models regarding ARRs,” said another stakeholder.

Horger said PJM had provided developers only information on ARRs from previous years because the Tariff requires a six-month lag before release. He said the values “don’t change much from year to year.”

“I agree it’s surprising to see negative values,” he added.

Moving Target

Herling said he hoped the next round of proposals would fare better. But he and Horger said developers will still face the risk of having proposals rejected because of the dynamics of the grid.

PJM will begin a new two-year planning cycle in January. Planners will conduct analyses through the spring and summer and release results in October, in time to open the next market efficiency window between November 2014 and February 2015. At the same time, however, PJM will be proposing upgrades to address reliability problems identified in their analyses.

(The PJM Board last week announced it has approved $4.6 billion in reliability upgrades, including a $1.2 billion project in the PSEG Zone. See Planners Choose $1.2B PSEG Short Circuit Fix.)

“For developers it’s somewhat of a moving target,” Herling acknowledged. Their projects “may be superseded by a reliability solution.”