Page 1626 – RTO Insider

July 15, 2014

SCC: Dominion IRP Lacks Analysis of Nuclear Plans

Despite closing its Wisconsin nuclear plant prematurely last year, Dominion Resources wants to keep its options open in Virginia, where it is considering a third unit at its North Anna nuclear plant.

But it hasn’t done any analysis to compare the risks of a new plant against an increasing reliance on natural gas-fired generation, Virginia State Corporation Commission staff said in a filing last week.

Responding to Dominion Virginia Power’s 2013 Integrated Resource Plan, staff said such an analysis should be included in the company’s next IRP in 2015 in order to determine which option the company should follow in the future.

Dominion “believes that uncertainty associated with the price of natural gas over the long term is a greater risk than the development cost uncertainty of a nuclear unit. However, the company concedes that no analysis has been performed to support this assertion,” SCC staff said. Staff said Dominion has indicated a willingness to conduct the analysis.

Two Plans

In its 2013 IRP, Dominion presented two different plans, one it called the “Base Plan” that calls for the expansion of generating capacity through new natural gas-fired plants, and one it calls the “Fuel Diversity Plan,” which includes low-emission options and does not rely so heavily on natural gas.

Both plans are very similar in the short run, with the major difference being that the latter plan includes the construction of North Anna 3. The company has chosen to follow the Base Plan, the least cost option, but it will also continue to go “forward with reasonable development efforts of additional resources included in the Fuel Diversity Plan,” which “would preserve the company’s ability to implement these alternatives should future conditions warrant,” SCC staff noted.

While natural gas plant projects have low development cost risk, the historically volatile fluctuating fuel price creates the risk of high operating costs. Nuclear plants generally have low operating costs, but their construction is very complicated and prone to cost overruns.

“In other words, there is a risk trade-off of higher operating cost risks with the Base Plan and higher project development cost risks with the Fuel Diversity Plan,” SCC staff said. “Staff was unable to determine whether the Base Plan contains too much operating cost risk, or whether the development cost risk associated with the Fuel Diversity Plan is greater than or less than the reduction in operating cost risk the Fuel Diversity Plan would achieve, because the company did not perform an analysis of this risk trade-off in its IRP.”

Dominion, which applied for Nuclear Regulatory Commission approval of North Anna 3 in 2003, has not committed to building the unit. In its IRP, the company said it would make its final decision once it received a Combined Operating License from the NRC. The unit would be completed no earlier than 2024.

Risky Business

The recent boom in natural gas production, resulting in cheap prices, has not been kind to the nuclear industry. Dominion learned this the hard way last year, when the company was forced to close the 556-MW Kewaunee Power Station, which it had purchased in 2005 for $192 million. After utilities did not renew their power contracts with the Wisconsin plant and Dominion failed to buy other nuclear plants in the region, the company attempted to sell Kewaunee in 2011. When it became apparent there were no buyers, Dominion closed it.

Kewaunee, which opened in 1974, closed a year shy of its 40th birthday, when its license would have needed renewal. Staff at the plant are now beginning the long process of decommissioning it.

With North Anna 3, Dominion seeks to keep all of its options on the table. Mark Kanz, local affairs manager for Kewaunee, recently told Nuclear Power International magazine that the prospect of North Anna 3 “proves that the company sees the benefit of nuclear and is looking forward to continuing that into the future.”

SCC staff also wants the company to compare the costs of building a third unit with the costs of extending the operating licenses of the first two, along with the licenses of the two units at its Surry nuclear plant.

“Given that these units still provide extremely efficient and dependable baseload generation for the company, and given the extremely high costs of constructing new nuclear plants, staff believes that the company should engage in serious discussions with discussions with the NRC to determine whether renewing these licenses is possible.”

The staff noted that it is unknown whether the NRC would grant renewals to the current units. The units would be 60-years-old when their licenses — already extended by 20 years — expired. The NRC expects the first application for an extension beyond 60 years to be filed in 2018 or 2019. Without additional license extensions, the country would face a wave of nuclear plant retirements during the next decade.

July 15, 2014

Losing Bidders Blast Artificial Island Choice

Two losing bidders for the Artificial Island transmission project have issued harsh critiques of PJM’s handling of the solicitation, seeking to persuade the Board of Managers to reject planners’ recommendation that the project be awarded to Public Service Electric & Gas.

In letters to the board, Northeast Transmission Development, a unit of LS Power, and Atlantic Grid Development, whose backers include Google, allege the competition was tainted by favoritism and that the PSE&G project will have difficulty winning siting approval. The challengers also contend the technical design of the winning project is inferior to their own proposals.

Atlantic Grid’s proposal failed to make PJM’s list of finalists. LS Power’s project was the low-cost proposal among the 10 finalists until PJM planners revamped the PSE&G proposal and deemed it equal in cost to LS Power’s at $211 million to $257 million. The changes reduced PSE&G’s price tag by $832 million, a 78% reduction. The estimates do not include an additional $80 million for a static VAR compensator, which PJM added to all of the proposals. (See PSE&G Wins $300M Artificial Island Project.)

In his letter, Northeast Transmission President Paul Thessen said PJM’s cost estimate for his company’s project is too high. He said the company estimates its project at $149 million and will cap its recovery at $171 million, a savings of at least $40 million to $90 million over the PSE&G project.

The board is scheduled to consider the staff recommendation at a meeting July 22.

“After careful evaluation, PJM’s staff concluded that ours was the best proposal. We believe that is the correct choice,” PSE&G spokesman Mike Jennings said in a statement. “We have successfully completed transmission projects in environmentally sensitive areas and performed that work on time and on budget. We are committed to doing the same with this project.”

PJM spokesman Ray Dotter declined to comment on the critiques. “We can say in general that our approach, which was made clear all through the development of our Order 1000 filing and reiterated throughout the Artificial Island evaluation process, is that we would look for the most cost-effective transmission solution,” he said.

Unwarranted Preference

Atlantic Grid said PJM planners gave PSE&G an “unwarranted preference” based on its participation in the Lower Delaware Valley Transmission System Agreement (LDV), a 1977 compact that controls right of way along the recommended project path between the Hope Creek nuclear plant and Red Lion, Del. Other signatories are JCP&L, Delmarva Power & Light, Atlantic City Electric and PECO.

Crediting PSE&G for the LDV right of way ignores the fact that about half the route is over federal and state land, where it may be difficult to obtain siting approval, Atlantic Grid said. In addition, the LDV right of way, the route of an existing 500-kV circuit, will need to be widened by as much as 200 feet in some locations.

Atlantic Grid said the PSE&G project “has a high likelihood of being rejected” by state or federal permitting agencies because it crosses wildlife protection areas and about 59 water bodies and may adversely impact endangered or threatened species. As a result, the ultimate fix “will be substantially delayed because PJM has proceeded down a dead end,” wrote Atlantic Grid President Robert L. Mitchell.

The New Jersey Board of Public Utilities (NJBPU) submitted comments raising the same concerns before planners announced their recommendation last month.

Atlantic Grid said PJM and its engineering consultant, GAI Consultants Inc., failed to seek a pre-application review from the New Jersey Department of Environmental Protection, which could have provided an indication of the project’s chances of winning required permits. “If GAI had followed this process its report might well have raised stronger cautions,” Atlantic Grid said.

Reliability of Design

Atlantic Grid also said the planners’ choice does not provide black start support for Artificial Island and ignores Nuclear Regulatory Commission regulations requiring nuclear plant switchyards be served by two physically independent circuits to minimize the likelihood of simultaneous failure. The PSE&G project would add a 500-kV line paralleling LDV’s existing 500-kV circuit.

Home to the Hope Creek and Salem nuclear plants, New Jersey’s Artificial Island is one of the largest nuclear complexes in the country.

26 Proposals

PJM asked for solutions to a stability problem at the complex last year. Five utilities and three independent developers responded with 26 potential solutions ranging from $100 million to $1.5 billion.

Atlantic Grid’s proposal, which would have buried an HVDC transmission circuit in public road rights of way between Artificial Island and Cardiff, N.J., appears to have been rejected early in the process. PJM cited its $1.01 billion cost and said it failed stability performance tests.

PSE&G, whose sister company PSEG Nuclear LLC operates the Salem and Hope Creek nuclear plants, submitted 14 alternative solutions, more than any other competitor.

One PSE&G proposal, 7K, envisioned a new New Freedom-Deans 500-kV line and a new Salem-Hope Creek-Red Lion 500-kV line at a cost of $1.066 billion.

The 7K project PJM planners recommended last month included several major changes that PJM says reduced the price by more than three-quarters.

Atlantic Grid criticized planners for modifying proposals that initially failed the technical review to allow them to qualify. “Some proposals were modified more than others, and others were not modified at all, raising significant questions about why PJM discriminated in this manner and the fairness of the process,” Atlantic Grid said.

“It appears that PJM took the proposals and then re-engineered a solution it liked best by mixing and matching pieces from different project proposals. The result is that PJM’s recommended 7K Project looks almost nothing like the original 7K proposal submitted by PSE&G.”

PJM Review

PJM planners began reviewing the proposals in July. In October, planners told the Transmission Expansion Advisory Committee they had narrowed their focus to the lowest-cost projects, which proposed interconnecting with facilities in Delaware. They also said they intended to add static VAR compensators to all proposals to provide reactive support.

By February, the focus had narrowed to proposals using two routes to connect to Delaware: a northern path that would add a 17-mile 500-kV line that parallels the existing 500-kV line from Red Lion to Hope Creek, and a southern crossing using a 230-kV circuit. The northern crossings included PSE&G’s 7K proposal; among the southern crossings was LS Power’s proposal, 5A.

By the March TEAC meeting, PJM planners apparently had decided to eliminate the New Freedom-Deans 500-kV line from the PSE&G proposal, showing its cost as proposed reduced to $297 million.

At a special TEAC meeting in May, planners said they also had eliminated a second tie line between the two nuclear plants from proposals by PSE&G and Dominion Virginia Power.

That reduced the estimated cost of the PSE&G proposal by about $43 million, giving it the same range ($211 million to $257 million) planners had assigned to the LS Power proposal, which had previously had been listed as the lowest cost option.

The elimination of the tie line also improved the performance of the PSE&G proposal in the planners’ rankings of the proposals.

PJM presented a chart summarizing its analyses of the proposals, assigning color codes for each of 25 attributes: green (positive or limited impact); yellow (some impact) and salmon (negative impact). RTO Insider summarized the findings by assigning a score of 1 to green, zero to yellow and -1 to salmon.

PSE&G’s 7K proposal scored a 1 out of a possible 25 in its original form but received a 9 when the second tie line was removed — the best of all 12 proposals analyzed. LS Power’s proposal scored a 7, ranking it third. (See Dominion, PSE&G Proposals Gain in Artificial Island Race.)

LS Power contends PJM planners underestimated the cost of the PSE&G proposal. The company said GAI Consultants estimated the cost of the 500-kV line at $5 million/mile while staff estimated only $3.6 million/mile. The consultants included an adder of $1 million/mile to account for construction in wetlands, which LS Power said PJM staff apparently did not consider.

LS Power also complains that PJM gave its proposal no credit for factors favoring its proposal, including rightofway, route diversity, black start, market efficiency, feasibility and system outage requirements.

Order 1000 Precedent

While LS Power wants PJM to accept its cost-capped proposal, Atlantic Grid asked the board to delay a decision until it evaluates the likelihood of the proposals to receive necessary siting approvals.

The challengers said the selection of PSE&G would set a bad precedent for future solicitations under the Federal Energy Regulatory Commission’s Order 1000, which was intended to open transmission development to competition.

“Unfortunately, if this RFP sets the pattern for the future, PJM will discourage participants from spending time, money and engineering resources to develop innovative, well-engineered RFP responses,” Atlantic Grid said.

July 15, 2014

MIC OKs Initiative on Gas Unit Offers

Members approved yet another initiative to address reliability concerns over gas-fired generators, agreeing to consider changes to the way such units submit energy and capacity market offers.

Under a problem statement approved by the Market Implementation Committee Wednesday, members will consider ways to reduce the confusion that occurred on the coldest days of last winter, when some gas-fired generators were unable to obtain fuel, some claimed costs above the $1,000/MWh offer cap and others ended up with “stranded” gas after PJM cancelled plans to dispatch them. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)

The effort will attempt to design rules that allow generators to submit offers that better reflect often volatile natural gas prices. Among potential changes: allowing generators to change their energy market offers during the operating day and submit differing hourly offers in the real-time market, as the New York ISO allows.

Carl Johnson, representing the PJM Public Power Coalition, expressed concern that stakeholders’ multiple gas-electric coordination initiatives could result in changes whose interactions are not well understood. “We have, at my count, six problem statements … on gas issues,” he said. “I’m concerned as we march forward … how these timelines will work together.”

Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS), also expressed concern. “The expectation for compromise gets less and less as you get more and more complex,” he said.

John Horstmann of Dayton Power & Light Co. suggested the issue could be handled by one of the groups already dealing with gas-electric issues. PJM staff agreed to review work assignments and make a recommendation at next month’s MIC meeting, when stakeholders will consider a proposed Issue Charge.

July 15, 2014

Life without Demand Response: Higher Prices but No Reliability Crisis, Says Monitor

PJM capacity prices would increase sharply but reliability would not be threatened if a recent federal court ruling eliminated demand response from wholesale markets, according to a new report by the Independent Market Monitor.

Market Monitor Joe Bowring said the sensitivity analysis released last week is intended to help stakeholders evaluate the impact of the May 23 ruling by the D.C. Circuit Court of Appeals that sharply restricts the Federal Energy Regulatory Commission’s jurisdiction over demand response compensation. (See DR’s Future Unclear Following Court Ruling.)

Revenue in the May base residual auction would have more than doubled to $16.86 billion from $7.5 billion if no DR or energy efficiency cleared, the analysis found. Cleared resources would have dropped by 3,290 MW, reducing reserves to 2% above the Installed Reserve Margin (IRM) from 4.4%. Bowring said the analysis included energy efficiency as “another form of DR,” which could be vulnerable under the court ruling.

Disruptive Ruling

On July 7, PJM joined FERC in asking the Court of Appeals to reconsider its ruling. “Extricating demand response from markets in which it has had years to integrate will be inherently disruptive and will inevitably raise countless unforeseen complications,” PJM said. While Order No. 745 was limited to economic demand response in daily energy markets, its implications are “potentially boundless.”

PJM’s petition overstates the impact of DR on reliability and understates the ability of PJM markets to respond, Bowring said in an interview Friday.

“If there’s a decision to eliminate [DR and EE] the market will adapt,” Bowring said. “Once you allow for other offers to respond to all this we would expect the prices to equilibrate — balance out — to the cost of new entry.”

Capacity prices doubled for much of the RTO in May’s base residual auction following rule changes that reduced the volume of limited DR and external generation that could clear.

Annual resources cleared at $215/MW-day for the PSEG zone, while the rest of the RTO cleared at $120/MW-day, about one-third of the $351 net cost of new entry (net CONE).

2.5% Holdback

The IMM’s study also looked at the potential impact of Bowring’s recommendation to eliminate a rule that reduces the volume of capacity resources procured in the BRA by 2.5%. Stakeholders last year rejected calls to eliminate the 2.5% holdback, which is intended to be filled by short lead-time resources procured in incremental auctions closer to the delivery year.

Had the holdback been eliminated along with DR and EE for the May BRA, capacity revenues would have more than tripled to $23.87 billion, or $396/MW-day, 13% above net CONE. The quantity of resources acquired would fall but remain sufficient to meet the IRM, the Monitor’s analysis found.

With the removal of DR and EE and the elimination of 2.5% offset “prices would have risen to greater than net CONE but less than the maximum price [1.5 times net CONE] and PJM’s reliability target would have been maintained,” the Monitor said.

The analysis assumed that all other variables are held constant, meaning that the real impact would likely be less because additional generation resources would have cleared the auction. “In the absence of demand side resources, some generating resources that retired in prior years might not have retired, and some new generation resources that did not clear in prior years would have cleared and both would have affected prices in subsequent auctions.”

The Monitor made no predictions on where prices would settle.

Concerns over Court Ruling

The D.C. Circuit ruled 2-1 that FERC’s Order 745, which requires PJM and other RTOs to pay DR full locational marginal prices (LMP), violates state ratemaking authority.

In its petition seeking a rehearing, PJM cited “the considerable uncertainty this decision has engendered” for PJM, which has used DR since 2000. Although PJM opposes Order 745’s equal-compensation mandate, General Counsel Vince Duane said the RTO sought rehearing because of concerns over the loss of DR.

PJM said the ruling appears to “forbid any compensation (regardless of the level) to economic demand response from the wholesale daily energy markets, not just the compensation change addressed by Order No. 745.”

“PJM does not have good options for replacing demand response capacity commitments on very short notice for the current summer, and replacing demand response capacity commitments for the next three summers (to the extent they even can be fully replaced) would likely be very costly,” PJM said.

The filing cited DR’s role in maintaining reliability during last September’s unexpected heat wave, when PJM was forced to shed load in some areas and during the arctic cold in January, when it “received more megawatts as load reductions than it could obtain as generation from all but the very largest generating stations.”

The RTO called for load reductions on 13 days in 2013. DR providers are committed to provide more than 8,000 MW of load reduction this summer and more than 10,000 MW for the summers of 2015-2017.

PJM said the loss of the wholesale markets might result in the elimination of many DR resources because the retail market cannot compensate DR for providing regulation, spinning reserves and day-ahead scheduled reserves, as PJM does.

In addition, it is unclear how DR procured through state-run retail processes could compete on price with generation procure in wholesale markets, PJM said. “There should be no mistake that pulling voluntary demand resource offers out of the grid operators’ single-clearing price markets will significantly reduce competition in those markets.”

This would contradict Congress’ direction in the 2005 Energy Policy Act to encourage demand response and eliminate “unnecessary barriers to demand response participation in energy, capacity, and ancillary service markets,” PJM said.

July 15, 2014

PJM: Black Start Sources Ready to Replace Retiring Coal

PJM officials said last week they have acquired sufficient new black start capacity to replace coal-fired units that will retire over the next year due to environmental rules.

PJM’s black start capacity will decline to 8,070 MW (150 units) from 8,720 MW (195 units), PJM’s Dave Schweizer told the Market Implementation Committee Wednesday.

Schweizer said PJM will have adequate supplies despite the reduction because of a redefinition of “critical load” and a rule change allowing units in one zone to provide service to others.

The redefinition — which will include units with hot start times of four hours or less — will increase the number of critical load units to 600 from 475 while reducing the total capacity to 2,910 MW from 4,780 MW.

PJM’s black start costs for 2016-17 will total more than $72 million, a 1.8% increase over 2015-16, according to an analysis by the Independent Market Monitor. Some zones, such as Dominion (+39%) and DPL (+27%), will see large increases, while others, such as Commonwealth Edison (-30%), will see sharp drops.

The RTO completed a solicitation for new black start resources because the Environmental Protection Agency’s Mercury and Air Toxics rule (MATs), which takes effect next year, will result in the shuttering of dozens of coal-fired plants.

PJM will attempt to win stakeholder approval for limited changes to the compensation rules for black start units and for a plan for selecting “backstop” resources for regions that fail to secure service through competitive solicitations.

In February, stakeholders rejected two proposals that would have boosted payments to existing black start units by at least 40%. On July 31, the Markets and Reliability Committee will consider smaller compensation changes. (See PJM to Seek Smaller Black Start Changes.)

July 15, 2014

PJM Considering IRM Change for Winter

PJM officials are considering boosting the RTO’s installed reserve margin (IRM) for winter as a result of its experience in January, when it narrowly avoided shedding load amid frigid temperatures and high outage rates.

PJM’s Tom Falin told the Planning Committee last week that a winter IRM is among the responses officials are considering based on a loss-of-load analysis that highlighted the winter risks.

PJM’s current IRM requirement is based on its summer peak demand and the assumption that generator-forced outages occur randomly at a constant rate under all load and temperature conditions.

In early January, however, PJM saw outage rates three times the assumed 7.35%, with many generators unable to start or obtain fuel due to the cold.

As a result, PJM recently conducted a loss-of-load analysis for the winters of 2014/15 and beyond to determine the risk of the RTO having insufficient resources to meet load.

The analysis found that on a 90/10 peak day next winter (90^th percentile of winter loads), there is a “virtual certainty” of load shedding if 18% of generation is lost to weather outages and maintenance in addition to the year-round 7.35% outage rate, Falin said.

The situation could be more dire in 2015/16 as a result of retirements resulting from the Environmental Protection Agency’s Mercury and Air Toxics rule. The analysis finds a 90% chance of load sheds on a 90/10 winter peak day with only 12.5% in additional outages.

Falin said the results indicate that only 7.4% of PJM’s generation can be “at risk” of winter-related outages to remain in compliance with the “one day in 10 years” loss-of-load expectation on which PJM’s IRM is based.

As a result, he said, PJM is considering proposing either a winter IRM or ensuring that no more than 7.4% of the resources clearing in the capacity market are at risk of cold-related outages.

James Wilson, a consultant to state consumer advocates, said the analysis was conservative and misleading because, among other assumptions, it ignored energy efficiency and assumed no demand response available in the winter.

Falin said the assumption was justified, noting only 43 MW of annual DR cleared for the upcoming winter.

Wilson noted that the threshold identified by PJM was based on preventing any non-zero increase in LOLE, which might lead to costly policies to limit at risk units. He suggested a threshold be applied, as PJM has done in other contexts.

Members OK Load Model for IRM

In related news, the Planning Committee last week approved a PJM staff recommendation to use an eight-year load model (2004-2011) for this year’s reserve requirement study.

Planners chose the model from among 36 candidates ranging in length from seven to 14 years. They said it did well in two coincident peak analyses and was a more recent time period than the other alternatives.

The load model will be used in resetting Installed Reserve Margins for 2015/16, 2016/17 and 2017/18, as well as establishing the initial IRM for 2018/19.

July 1, 2014

Load, Supply Deadlock on MOPR Changes

Load and supply factions deadlocked Thursday, as members rejected three proposed changes to the Minimum Offer Pricing Rule. The score was nil-nil-nil for proposals by PJM, PSEG and a joint plan backed by Maryland regulators and consumer advocates.

At issue was the MOPR unit-specific review process, which sets a floor price for capacity resources that do not qualify for the self-supply or competitive entry exemptions.

PJM and the Independent Market Monitor had proposed changes they said would standardize some parameters and reduce the subjectivity in the review. Market Monitor Joe Bowring said “it’s difficult to tease out” questionable developer cost assumptions in the 30 days the Monitor has to conduct the MOPR review.

The PJM-IMM proposal would have required use of nominal levelized values, a 20-year asset life and a residual value of zero. It would also bar inclusion of sunk costs. Although it received wide support in a poll by the Capacity Senior Task Force, it received only a 44% endorsement support in sector-weighted voting at the Markets and Reliability Committee Thursday.

Inconsistent with FERC Order

Walter Hall of the Maryland Public Service Commission said the proposal was “inconsistent” with a Federal Energy Regulatory Commission order requiring PJM to maintain the unit-specific review and would increase prices as much as 30%.

By assuming that any new generation came from merchant generators with B-rated debt, it prevented generation developers from offering prices that reflected capital cost advantages, Hall said. PJM and the IMM also chose a nominal levelized costing formula that inflates costs and has been rejected by PJM’s consultant, The Brattle Group, Hall said.

The proposal would have also barred inclusion of revenues from power purchase agreements outside of PJM and required developers to recover the costs of turbines and other equipment that typically operates for 40 years in only 20 years, with an assumption of no residual value at the end of that period. By contrast, ISO New England rules recover costs over 35 years and allow for residual value, Hall said.

Pamela Quinlan of Rockland Electric also criticized the 20-year recovery without residual value, saying it was “overly conservative.” Quinlan said, however, that her company supported the PJM-IMM proposal.

An alternative by PSEG Energy Resources & Trade also fell short at 41%. PSEG’s Ken Carretta said it would have used the best available evidence of the developer’s costs, while the PJM-IMM proposal would provide developers incentives to understate costs.

Hall said the PSEG proposal included most of the features that Maryland found objectionable in the PJM-IMM proposal.

Generation Owners and Transmission Owners generally supported the PJM and PSEG proposals, which won only 45% support from Other Suppliers and no votes from End Use Customers and Electric Distributors.

Suppliers Turn the Tables

After the PJM-IMM and PSEG proposals failed, suppliers turned the tables to reject a proposal by the Maryland PSC and the Maryland Office of People’s Counsel. It won only 35% support. (Package B in the MOPR Unit Specific Review Matrix.)

It won unanimous support from the EUC sector but less than 40% from the ED and OS sectors and virtually no support from Generation and Transmission Owners.

Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS) said the Maryland proposal would retain much of the current rules. “We are open to … establishing a neutral process” for better defining some parameters in the review, he said.

PSEG’s John Citrolo said the proposal would allow the exercise of buyer-side market power, which the MOPR is designed to prevent.

“Long-term contracting can lower costs and shouldn’t be considered a subsidy,” Hall responded.

With no proposals receiving two-thirds support, the issue will be returned to the CSTF. “Send it back to the committee and see if they can wrestle a consensus,” said PJM Executive Vice President for Operations Mike Kormos, the MRC chair.

July 1, 2014

MISO to Withdraw FERC Filing on Emergency Costs

The Midcontinent ISO has agreed to withdraw a unilateral petition to amend the MISO-PJM joint operating agreement (JOA) after PJM officials protested.

Stu Bresler, PJM vice president of market operations, told the Markets and Reliability Committee Thursday that PJM and MISO will make a joint filing with the Federal Energy Regulatory Commission to replace MISO’s June 11 filing in docket ER14-2159.

The filing was intended to ensure that MISO is reimbursed for transmission charges it may incur in providing emergency energy to PJM. It was prompted by the ISO’s dispute with the Southwest Power Pool (SPP) over the use of SPP’s transmission system to deliver power between MISO’s Midwest and South regions.

MISO’s filing asked for permission to pass through to PJM additional costs it would incur if MISO exceeds the 1,000-MW contract path limit between the Midwest and South regions to supply emergency energy to PJM.

PJM had informed MISO that it did not believe the filing was necessary because the existing JOA language is broad enough to cover the SPP charges. “However, it is MISO’s customers that are at risk, not PJM’s customers, if that interpretation proves incorrect in a future dispute,” the ISO said in its filing. “Rather than mitigate that risk by simply refusing to supply emergency energy, MISO prefers to eliminate any doubt that such charges can be recovered if an emergency does arise.”

On Jan. 28, SPP proposed a 200% penalty rate for transfers of real-time energy in each direction between the MISO Midwest and South regions that exceed the 1,000-MW limit of the physical tie between Ameren and Entergy Arkansas (ER14-1174).

The commission approved the rate on March 28 subject to refund and directed SPP and MISO to engage in settlement talks. Settlement Judge Carmen Citron reported last week that talks were progressing and should continue.

Bresler told the MRC that MISO’s original filing was overly broad. The joint filing “will be much more specific than what was originally proposed,” he said.

July 1, 2014

W.Va., Ky. Reluctant to Join PJM, RGGI in Carbon Reductions

HERSHEY, Pa. — PJM and state officials pledged last week to develop a regional plan to minimize the cost of complying with the Environmental Protection Agency’s proposed carbon emission rule. But lawmakers in coal-dependent Kentucky and West Virginia may be more interested in fighting the regulation than in joining in.

Jon McKinney, WV PSC Commissioner eyeing EPA's Joe Goffman — Jon McKinney, WV PSC Commissioner eyeing EPA’s Joe Goffman

“For [a regional solution] to actually happen, it goes way beyond the public service commissions. It has to get [approved by] the governors and the legislators,” West Virginia Public Service Commissioner Jon McKinney told the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) annual education conference. “I’m handcuffed in my ability to do that. It has to start someplace else.”

Kentucky Public Service Commissioner Jim Gardner said his state “is of two minds” on how it should respond to the proposed rule, which calls for an 18% cut in the state’s carbon emissions by 2030.

While the state’s energy and environment secretary drafted a white paper outlining how the state might respond, the legislature rejected the proposal and enacted a law that prevents the state from complying with all but the first of four “building blocks” the EPA used in calculating state targets, Gardner said. Building block No. 1 is efficiency improvements at existing coal-fired generators.

Joe Goffman, EPA associate assistant administrator, told the gathering that the agency encourages regional compliance, saying that it “tried to make the state boundaries as permeable as possible.”

He said the EPA may consider additional building blocks if they are proposed by states. These are the “early days in our decision making,” he said.

RGGI

Commissioner Kelly Speakes-Backman, MD PSC

Maryland Public Service Commissioner Kelly Speakes-Backman said she was pleased that the EPA mentioned the nine-state Regional Greenhouse Gas Initiative (RGGI) as a potential vehicle for compliance. Maryland and Delaware are the only PJM states currently participating; New Jersey withdrew in 2011.

“We’ve been there. We’ve done that. We’ve been doing it for five years,” Speakes-Backman said. “It just makes perfect sense to me to comply with an environmental rule that affects power plants aligning with the regional nature of our grid … I just can’t see how we do this otherwise.”

PJM: Ready to Help

Mike Kormos, PJM’s executive vice president for operations, told regulators that the RTO can incorporate state implementation plans into its economic dispatch engine.

Mike Kormos, PJM Executive Vice President of Operations

“There’s many ways you can do it that are maybe something short of a full-blown environmental dispatch,” Kormos said. “There’s ways to price that … that’s a conversation that we’ll have to have with the states.

“We would love to help you model what you are thinking — what the impacts might be, what those unintended consequences may be — and try and get that all out in the open and hopefully bring the best plan for consumers,” he said.

But West Virginia, which the EPA says should cut its carbon emissions by 20% by 2030, may not be ready to embrace a regional approach, McKinney said.

“There may be a middle-American response to this that’s different from the coastal-American response,” he said. “We have legislators and governors who have taken, in some cases, a very opposed case to EPA.”

McKinney suggested some of the opposition is a reaction to what he called the “misleading way” the agency is selling the proposal.

He said the agency underestimated the likely impact on electric rates and coal-state jobs and overestimated the health benefits of the rule by counting the same benefits under multiple EPA programs.

Partial Agreement

Gardner asked Kormos whether Kentucky could swap its state target for participation in a regional compliance plan if not all states agreed.

Kormos said that while PJM would prefer all member states agree to participate in a regional plan, the RTO could work with only a “core set of states.”

“It will obviously work best if … all the states [are] in and are cooperative. I think then we will be able to use all the tools of all the states because I think the states will have different competitive advantages to be able take advantage of different building blocks.”

Kormos cautioned that state implementation plans (SIPs) will affect each other under PJM’s economic dispatch. “While you may have thought your high-carbon units were not going to be dispatched based on whatever you’ve done, if your neighbor has just flat-out retired his [units], ultimately we’re going to end up running yours to supply his load. And that may in fact end up in some cases undoing what you thought [you had accomplished.]”

Kormos said PJM has not drafted any rule changes to respond to the carbon rule “because there’s a lack of understanding on our part on how the states want to respond.”

“Let’s start the conversation early. We’re not bashful about making changes. We’ll make the changes we need to make to keep the system reliable.”

Dallas Winslow, chair of the Delaware Public Service Commission, said his state is eager for the conversation. “We now need to communicate amongst ourselves and also with our governors’ offices and then we need to collaborate over the next 10 months … and see how it is we can help each other,” he said. “I think this probably will slide by us. Two years from now we’ll look back and say, `Wow, we worked together and we were successful.’”

Base Year Question

While many regulators seemed accepting of the carbon rule, others called for changes.

Some states have called for changing EPA’s proposed 2012 baseline year to 2005 so that they get credit for emission reductions over the past decade.

Pennsylvania Public Utility Commission Chair Robert Powelson said a 2012 baseline means the state wouldn’t get to count the impact of its renewable portfolio standard and nuclear uprate projects made between 2005 and 2012. He said Pennsylvania has invested $1 billion in energy efficiency and retired 5,000 MW of coal-fired generation.

PJM CEO Terry Boston noted that 2012 had lower emissions than 2013, when rising natural gas prices caused a rebound in coal-fired generation.

But the EPA’s Goffman said that the agency must be forward-looking because its regulations require limits set based on the “best system of emission reduction adequately demonstrated” (BSER).

“The threshold question we’re really asking is ‘What is the next thing that a source can do to further reduce their emissions,’” Goffman said.

“All we did, in a way, was look at each state’s existing [generation] fleet and look at technologies that have been exhaustively demonstrated as a way of achieving reductions and applying those reductions to each state’s existing fleet.”

Robert Powelson, chair of the Pennsylvania Public Utility Commission

The agency had to set the targets “in a way that doesn’t have a perverse effect of having emission reductions that have already occurred offset emission reductions in the future,” he said.

Speakes-Backman said the EPA’s plan was fair, even if it does require Maryland to reduce emissions by 37% — more than either West Virginia or Kentucky. (See Carbon Rule Falls Unevenly on PJM States.)

“If they had taken 2005 as a baseline instead of 2012 they could have just made our goal not 37% but 75%,” she said.

Powelson said that the EPA needs to demonstrate its flexibility by “fast-tracking” the process of approving natural gas pipelines that states need to continue the transition from coal to gas-fired generation.

“Phil, I’m not letting you off the hook,” Powelson said, turning to Federal Energy Regulatory Commissioner Philip Moeller. “You guys need to move quicker [on pipeline approvals] as well.”

July 1, 2014

PJM to Seek Rehearing on FERC Order 745

PJM will join in calls asking the D.C. Circuit Court of Appeals to reconsider its May 23 ruling sharply limiting federal jurisdiction over demand response.

PJM General Counsel Vince Duane told the Markets and Reliability Committee last week that the RTO will join the Federal Energy Regulatory Commission in seeking to reinstate FERC Order 745, which required PJM and other RTOs to pay demand response resources market-clearing prices.

The court ruled 2-1 that FERC’s order violates state ratemaking authority. (See Court Throws Out Demand Response Rule.)

Duane said PJM’s filing, which he said will be akin to an amicus brief, will express the RTO’s support for maintaining federal jurisdiction of DR under the Federal Power Act. Duane said the RTO was acting out of practical concerns — the need for DR this summer — despite the fact that it opposes Order 745’s equal-compensation mandate.

Duane acknowledged that the court grants less than 1% of the rehearing requests it receives. But given the implications of the ruling, he said, “There’s a sense that this has got a much better chance than average.”

“It allows us to preserve our options,” he said. With an appeal pending, “we can continue to rely this summer on demand resources. We don’t have any practical alternative to replacing these resources in short order.”

Order 745 required PJM and other RTOs to pay DR participating in the day-ahead and real-time energy markets locational marginal prices identical to those for generation. The order only applied when DR was capable of balancing supply and demand and lowered the market-clearing price.

FERC said it had authority for the order under sections 205 and 206 of the Federal Power Act because reducing retail consumption through DR can aid reliability and lower wholesale prices. The commission made a distinction between “price-responsive” DR, which it acknowledged was a retail product subject to state regulation, and DR response to incentive payments, which it called “wholesale demand response.”

The court’s majority disagreed, saying “a reduction in consumption cannot be a ‘wholesale sale,’” and thus does not come under federal jurisdiction. The commission “went far beyond removing barriers to demand response resources,” as Congress had ordered in the Energy Policy Act of 2005, the judges ruled.

“This is a big, sweeping decision with national implications,” Duane said.

The ruling was a subject of discussion at the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) annual education conference.

New York Public Service Commission Chair Audrey Zibelman, PJM’s former chief operating officer, said the court “got it wrong.”

“The states have the ability to delegate to the federal government through the RTOs if we want to,” Zibelman said. “I think that’s what [Order] 745 said. If we wanted to do demand response through the RTOs we can do it. If we want to do it ourselves we can do it.”