Page 1835 – RTO Insider

May 20, 2014

Cooling Water Rule: 7,000 MW Lost in PJM?

By David Jwanier and Rich Heidorn Jr.

WASHINGTON — PJM could lose as much as 7,000 MW of generation by 2018 under long-awaited cooling-water regulations approved late yesterday by the Environmental Protection Agency.

The rule will require steam generators in PJM to take steps to reduce the volume of fish and other aquatic life sucked into their cooling water intakes.

The final rule affects about 544 power plants, including nuclear-, coal-, gas- and oil-fired steam generators. More than 500 industrial sites, including pulp and paper mills; chemical, iron, steel and aluminum manufacturing plants; refineries; and food processors, are also covered by the rule.

The EPA said about 40% of affected units are already using the “best available technology” as required by the regulations, which were issued under section 316(b) of the Clean Water Act.

The EPA estimates that 2.1 billion fish, shrimp and crabs are killed annually by being pinned against cooling water intake structures (impingement) or being drawn into cooling water systems (entrainment).

Industry officials were relieved in 2011 when the EPA announced its proposed rules, which did not include a requirement that all generators install expensive closed-loop cooling systems employing cooling towers. The EPA is also delegating enforcement largely to state environmental officials. (See related stories, What’s Covered by EPA Cooling Water Rule?)

PJM spokesman Ray Dotter said the RTO has not done any studies to evaluate the potential impact of the regulations but will review the final rule. “We did look at the proposed EPA rule and believe it provided flexibility to the states to conduct unit-specific determinations, which would minimize the impact to generation,” Dotter said.

The North American Electric Reliability Corp. published an analysis of the proposed rule in November 2011, which projected at least 25,000 MW of retirements or deratings nationwide by 2018 under a “moderate” regulation, including about 7,000 MW in PJM (1,300 MW of deratings and 5,700 MW of retirements).

The moderate case is estimated to cost $170 to $440 per gallon per minute (GPM).

The moderate case assumed only “more aggressive” states would require closed-loop systems. NERC said those states — including Delaware and New Jersey in PJM — are home to three-quarters of affected generation.

NERC projected PJM generators installing cooling towers would lose an average of 1.6% of their energy output.

NERC’s analysis, and a 2011 analysis by ReliabilityFirst Corp., assumed no nuclear plants would retire as a result of the rule, although RFC said retrofits would cut nuclear capacity by 3.5%. That, however, was before nuclear operators began threatening to shutter units because of low capacity and energy revenues.

Oyster Creek Generating Station (Source: Exelon)

PJM is already losing Exelon’s Oyster Creek nuclear plant by the end of 2019 — 10 years before its license expires — under a settlement with the New Jersey Department of Environmental Protection.

NERC predicted PJM would need more generation or additional demand response by 2018 under the moderate case and by 2015 under the “strict” case. The strict case, which would have required closed-loop systems and boosted generators’ costs by 25%, could have caused 35,000 MW in retirements and deratings nationwide, NERC estimated.

In its 2013 10-K filing, Public Service Enterprise Group said it was “unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material.”

Exelon’s 2013 10-K filing, issued in February, said that under a final rule that did not require cooling towers, and allowed states’ permitting agencies to apply cost-benefit tests and consider site-specific factors, “the impact of the rule would be minimized even though the costs of compliance could be material.”

Exelon said its generators without closed-cycle recirculating systems include the Clinton, Dresden, Peach Bottom, Quad Cities, Salem, Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna nuclear plants in addition to Oyster Creek. Also affected in PJM are the Eddystone, Gould Street, Riverside and Schuylkill fossil fuel plants as well as the Fairless Hills plant, which burns landfill gas.

May 20, 2014

What’s Covered by EPA Cooling Water Rule?

The North American Electric Reliability Corp.’s 2011 review of EPA’s cooling water regulations had assumed that the rule would affect 1,200 generators with once-through cooling systems. EPA’s announcement of the final rule yesterday said it would affect less than half as many plants, however.

Covered are:

Existing facilities that withdraw more than 2 million gallons per day (MGD) of water from waters of the U.S. and use at least 25% of their withdrawals exclusively for cooling. They are required to reduce fish impingement using one of seven options.
Facilities that withdraw at least 125 MGD, which must conduct studies to determine whether controls will be required to reduce entrainment.
New units at an existing facility that are built to increase its generating capacity of the facility. They will be required to reduce the intake flow to a level similar to that of a closed-cycle system.

May 20, 2014

PJM, FERC: Grid is Ready for Summer

After a record-breaking winter in which it narrowly avoided load shedding, PJM says it is confident it can keep air conditioners running this summer. But forward prices suggest costs may be higher than last year.

“Our experience with extreme seasonal weather and conditions over the past couple of years has helped us to better prepare for hot summers [such as] the one we expect this year,” Mike Kormos, executive vice president for operations said in a press release last week.

PJM’s summer peak is forecast at 157,279 MW, a 1.3% increase over 2013’s forecast and virtually identical to last summer’s actual peak.

With 183,220 MW of installed generation capacity and 11,160 MW of demand response and energy efficiency, PJM says its reserve margin will exceed 25%, well above the required 16.2%. The RTO’s all-time peak was 165,492 MW in July 2011.

Transmission Upgrades

PJM said reliability will be enhanced by transmission upgrades completed since last summer, including two bulk electric system transformers and about 500 MVAR of shunt capacitors.

In its own summer assessment last week, the Federal Energy Regulatory Commission said congestion in PJM should be reduced thanks to two 500-kV projects scheduled to enter service in June, the Mount Storm-Doubs rebuild and the Hopatcong-Roseland segment of the Susquehanna-Roseland project.

National Outlook

FERC said forecast reserve margins are adequate across the country despite a net reduction of 10 GW in capacity since last summer, including a 2.5 GW cut in PJM. The commission said it is expecting a hotter than normal summer although some forecasters are predicting an El Nino, which could moderate temperatures.

The hurricane forecast is slightly below average, with 10-12 named storms expected, four or five of which are likely to become hurricanes.

Summer Electric Futures (Source: FERC, May 2014) — (Source: FERC)

Electric futures for the summer have jumped since November, with increases of 19% to 30% for the Mid-C, NYISO Hudson Valley and ISO-NE hubs. PJM-West is up by about 25%. [See chart]

FERC said the increases reflect the boost in natural gas futures resulting from winter demand, which left storage inventories below normal. Henry Hub summer futures averaged $4.81/MMBtu in early May, 84 cents above 2013. Prices in the Mid-Atlantic are up almost 20%. Prices in New York City are about equal to last summer, 58 cents below Henry Hub.

With gas futures more than $1/MMBtu higher than coal futures, coal generation is likely to exceed gas, FERC said. Some coal-fired generators had difficulties obtaining fuel deliveries during the winter due to ice on barge routes and congestion and equipment problems on the rails. Rail network congestion will continue in some areas this summer because of competing demand from oil shipments in the Dakotas and the Upper Midwest.

The North American Electric Reliability Corp.’s summer Reliability Assessment said that pipeline maintenance and storage refills during the summer could limit natural gas availability for generators lacking firm service.

NERC also forecast adequate reserve margins but warned of potential challenges in ERCOT and MISO.

Below is a snapshot of FERC’s and NERC’s regional assessments:

CAISO: Gas-fired generation is likely to increase to offset lower hydropower output due to a prolonged drought. This could result in pipeline congestion and high gas prices although increased solar generation may provide some relief.

ERCOT: ERCOT forecasts a 15% reserve margin, just above its 13.75% target, thanks to four new combined-cycle plants totaling 2 GW. The generation is expected to enter commercial service by August, when Texas load typically peaks. “However, an early season heat wave could stress the system before these new facilities are available,” FERC warned.

MISO, SPP: MISO and SPP should benefit from lower production costs this summer: MISO as a result of the addition of the MISO South region and SPP from the launch of new markets in March. SPP added a day-ahead market with transmission congestion rights, a real-time balancing market and a price-based operating reserve market. It also combined multiple areas into a single balancing authority.

MISO’s reserve margin is slightly above NERC’s 14.8% requirement but lower than last year’s 18.1% due to generation retirements and suspensions, and limits on transfers between MISO’s traditional footprint and MISO South.

NYISO, ISO-NE: Transmission improvements will help the Northeast. The Greater Springfield Reliability Project should reduce congestion in western Massachusetts and northern Connecticut while full service of the Neptune line will increase imports to Long Island. FERC expects increased interchange between PJM and NYISO following changes in congestion management on the Ramapo line. Demand response will also be important on peak days.

May 20, 2014

Dominion, PSEG Proposals Gain in Artificial Island Race

Dominion and PSE&G appear to have vaulted into contention in the Artificial Island contest following a design change by PJM planners.

In a special meeting of the Transmission Expansion Advisory Committee yesterday, PJM planners presented charts summarizing their analysis of 10 finalist proposals to fix stability problems at Artificial Island, home of the Salem and Hope Creek nuclear plants.

A 230-kV proposal by LS Power (proposal #5A), which PJM had previously identified as the cheapest among the 10, fared well in the analysis.

But two 500-kV proposals by Dominion Virginia Power (#1C) and PSE&G (#7K) that were in the middle of the pack in cost — and did poorly in the analysis in their original forms — had their standings improve dramatically when PJM reevaluated them after eliminating a second tie line between the two nuclear plants.

The proposals not only got the top two scores in the analysis but also saw their costs reduced by $34 million and $43 million, respectively. PJM estimates either revised project would cost between $211 million and $257 million, the same range it assigned to the LS Power plan.

The estimates do not include an additional $80 million for static VAR compensators (SVCs), which PJM determined were necessary to improve performance of each of the proposals.

Cost Allocation

The LS Power proposal, which would run a 230-kV line across the Delaware River to a new or expanded substation on the Delmarva Peninsula, could face opposition from Delaware regulators. PJM told stakeholders at the last TEAC meeting that its cost would be allocated entirely to the Delmarva Power and Light zone. (See Delaware Unhappy with Artificial Island Cost Allocation.)

PJM did not provide an allocation for the revised Dominion and PSE&G proposals, which would both add a 17-mile, 500-kV line paralleling an existing 500-kV line from Red Lion to Hope Creek. But officials indicated yesterday that the allocation would be similar to that of a proposal by Exelon and Pepco Holdings Inc. that would follow an identical route. Its cost would be spread among two dozen transmission zones and merchants.

PJM will accept written comments on its analyses through June 2. It plans to review stakeholder feedback and present planning staff’s recommendation for the project’s design and developer at a special TEAC meeting June 16. The planners are scheduled to present their recommendation to the PJM Board of Managers July 22.

Color-Coded Summary

PJM yesterday presented a chart summarizing its analyses of the proposals, assigning color codes for each of 25 attributes in seven categories: green (positive or limited impact); yellow (some impact) and salmon (negative impact). (See p. 197 of the presentation.)

Steve Herling, vice president of planning, said each of the finalist proposals solve the stability problem. “All of these other issues are going to be factored in because the performance is so close,” he said.

Herling cautioned that the three colors included in the chart could not capture the subtleties of the planners’ analyses. “It’s a visual” summary, he said. “We don’t want people to read too much into it.”

RTO Insider summarized the findings by assigning a score of 1 to green, zero to yellow and -1 to salmon.

The PSE&G 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.

Dominion’s 1C proposal received a -2 in its original form but improved to an 8, second-best, without the tie line.

LS Power’s proposal scored a 7, ranking it third.

Tie Line Eliminated

Deleting the second tie line from the Dominion and PSE&G proposals not only reduced their costs. It also eliminated the proposals’ negative grades in the project complexity and operational impacts categories. The only remaining negatives for the two proposals related to their wetlands impact and land permitting issues.

Supawna Meadows National Wildlife Refuge (Source: US Fish and Wildlife Service)

PJM estimates the proposals will affect 350 acres of wetlands. But one stakeholder questioned that, saying only 30 acres — the ground under the transmission towers’ foundations — would be affected.

LS Power’s proposal received three negative grades under the operational impact, and siting and permitting categories. PJM said its plan for an overhead crossing of the Delaware was likely to face more public opposition than submarine crossings. “Out of sight, out of mind, if you will,” said Paul McGlynn, general manager of system planning.

The PSE&G and Dominion proposals also employ an overhead design but would follow an existing Delaware River crossing.

Sharon Segner, vice president of LS Power, said PJM should leave the decision regarding the manner of crossing the river to the U.S. Army Corp of Engineers, which has jurisdiction over the river. LS Power’s nearly identical proposal for a submarine crossing (#5A) would add as much as $45 million to the project cost.

Segner said the PSE&G and Dominion proposals face potential permitting problems because the route is within a half mile of 350 homes and includes three miles through the Supawna Meadows National Wildlife Refuge and 10 miles of wetlands.

PSE&G may have an edge over Dominion because it already owns some of the right of way needed. Sister company PSEG Nuclear LLC is the operator of the Salem and Hope Creek plants.

In its favor, LS Power holds an option on the site of its proposed substation in Delaware.

May 20, 2014

PJM Proposes Changes to Capacity Auction Parameters for 2015

PJM proposed changing the demand curve to be used in the 2015 Base Residual Auction while recommending the RTO continue using a combustion turbine as the model for determining the Cost of New Entry (CONE).

Proposed VRR Curve for 2015 Auction (Source: PJM Interconnection, LLC)

PJM’s proposed parameters adopt many of the recommendations from a study by The Brattle Group but differ on some issues, notably rejecting Brattle’s recommendation that CONE be determined based on an average of combustion turbine and combined cycle plant costs.

Brattle recommended that the Variable Resource Requirement Curve be changed so that the price cap (point a) for the system curve is set to a quantity equaling a loss-of-load expectation (LOLE) of one event in five years. Brattle said the change would provide stronger price signals when capacity resources are reduced or become more expensive and would not increase long-term average prices. The study also recommended stretching the VRR curve into a convex shape, making it steeper at lower reserve margins and flatter at higher reserve margins.

PJM said it favored the convex curve but would right-shift it by 1%, setting the price cap to 150% of net CONE at an unforced capacity (UCAP) level 0.2% below the installed reserve margin (IRM). PJM would use the same system curve for locational deliverability areas.

CONE Model

Brattle recommended using an average of combustion turbine and combined cycle costs as the reference technology for calculating Net CONE rather than the current reference of the GE Frame 7FA model combustion turbine.

Brattle said the change would acknowledge that combined cycle plants are the favored choice of merchant generators while avoiding a complete switch away from the current CT reference. It also recommended switching from the Handy Whitman “Other” Index to the Bureau of Labor Statistics’ indices for wages, materials and turbines, which it said would provide more accurate escalation factors for CONE estimates.

PJM agreed with changing to the BLS index but is recommending continued use of the frame-model CT as the reference technology, saying it would provide “market stability and avoids perceived opportunistic switching to units with more favorable economics in any given year.” It noted that the New York ISO recently selected a CT as its reference technology.

PJM seeks to have final stakeholder input by Aug. 31, with changes submitted to the Federal Energy Regulatory Commission by Oct. 1.

PJM Opposes Auction “Re-Run”

In a related matter, PJM asked FERC on May 9 to reject a request from the North Carolina Electric Membership Corp. to require the RTO to develop a mechanism for “unwinding” Base Residual Auction results and rerunning the auction. The scenario envisioned by NCEMC would occur if FERC ruled after the auction and reduced supply curve parameters below those filed by PJM.

“The hypothetical series of events that NCEMC envisions as warranting such a mechanism includes a Commission determination on how best to apply any final rulings on RPM parameter changes resulting from a periodic review,” PJM said in its response. “That opportunity for Commission intervention invalidates any suggestion that PJM’s current Tariff could lead to unjust or unreasonable results.”

NCEMC made the request in response to PJM’s April 4 proposal (ER14-1660) to move up by two months the deadlines for filing changes to auction parameters. Proposed parameter changes would be due May 15 instead of the current July 15. PJM said the changes will allow stakeholders more time to assess the parameters before the Base Residual Auction.

May 20, 2014

FERC to Relax OATT Rules for Tie Lines

The Federal Energy Regulatory Commission said it intends to grant a blanket waiver from Open Access Transmission Tariff (OATT) requirements for utilities whose only transmission assets are generator tie lines. The revisions are detailed in a Notice of Proposed Rulemaking (RM14-11).

Current policy requires a tie line owner to make excess capacity available to third parties unless it can justify its plans for future use of the line. The NOPR would allow tie line owners to wait until a third-party request for service is made under sections 210 and 211 of the Federal Power Act before having to demonstrate their plans.

The proposed changes follow a technical conference and a Notice of Inquiry issued in April 2012.

May 20, 2014

Order 1000 Reversal: Reality Check or Surrender to Incumbents?

PJM’s transmission planning process may exclude consideration of non-incumbent proposals on projects subject to state rights of first refusal (ROFR), the Federal Energy Regulatory Commission ruled last week.

FERC had previously required PJM to remove language designating an incumbent transmission owner as the “Designated Entity” to build a transmission project, “when required by state law, regulation or administrative agency order with regard to enhancements or expansions or portions of such enhancements or expansions located within the state,” and when a transmission project is “proposed to be located on a Transmission Owner’s existing right of way and the project would alter the Transmission Owner’s use and control of its existing right of way under state law.”

But the commission ruled 3-1 Thursday that its previous position would require planners to evaluate nonincumbent proposals that had no chance of getting built because of state rules assigning them to incumbent utilities. The commission said it was persuaded by the arguments of North Carolina Utilities Commission, the Indiana Utility Regulatory Commission and others that the language merely acknowledged state jurisdiction and did not create a federal right of first refusal.

The commission made the change in Order 1000 compliance rulings for PJM (ER13-198, ER13-195, ER13-90), MISO and South Carolina Electric & Gas Co. (SCE&G).

Norris Dissents

In a dissent, Commissioner John Norris said the reversal undercuts Order 1000’s requirement eliminating federal rights of first refusal from FERC-jurisdictional tariffs or agreements.

Norris cited Order 1000-A, in which the commission said “[I]t would be an impermissible barrier to entry to require, as part of the qualification criteria, that a transmission developer demonstrate that it either has, or can obtain, state approvals necessary … to be eligible to propose a transmission facility.

“By excluding proposals from non-incumbents when the proposals are being evaluated based on a consideration of state law, we are effectively excluding non-incumbents from participating in the transmission planning process,” Norris wrote. “This is a fundamental change in direction that I cannot support. I simply cannot reconcile the language in the final rule with the approach taken in today’s orders.

“Clearly, incumbents already are well-positioned through their knowledge of the system, including issues related to reliability and congestion,” he continued. “Today’s orders give incumbents a further advantage over non-incumbents by limiting non-incumbents’ participation in the planning process.

“In my view, allowing non-incumbents to participate in the regional transmission planning process without consideration of potential state law restrictions does not infringe upon the state’s authority,” Norris said. “Using this language to exclude non-incumbents denies states and other stakeholders the opportunity to have all essential information regarding the more cost-effective and efficient transmission solutions.”

‘Coercive Pressure’

The Indiana Commission said that allowing a transmission provider to select a transmission developer that is ineligible to construct a transmission facility under state law would lead to increased litigation and “coercive pressure on state commissions.”

The North Carolina Utility Commission and its public staff agencies said the commission was acting inconsistently in requiring that PJM consider state renewable portfolio standards in its transmission planning process while insisting it ignore state rules restricting transmission development to state franchised utilities.

Other Challenges Rejected

While the commission reversed its position on acknowledging state rules, it largely rejected challenges to its previous orders regarding PJM.

It did, however, order PJM to make some additional Tariff changes and compliance filings, including one describing how local transmission owners incorporate public policy requirements into their transmission plans.

It also ordered PJM Transmission Owners to submit a compliance filing ensuring comparable treatment of AC and DC facilities.

May 20, 2014

Consumer Advocates to PJM: No More Changes, Please

CAMBRIDGE, Md. — Consumer advocates asked the PJM Board of Managers last week to assess the impact of recent capacity market changes before making any new ones and criticized what they called the RTO’s new “inflexibility.” Environmental groups, meanwhile, asked PJM to become “proactive” in addressing climate change and to do more to capture the role of energy efficiency in its planning.

The comments came at the board’s yearly meeting with consumer advocates and public interest groups on the first day of the PJM Annual Meeting here. The tone was a bit less rancorous than 2013’s meeting, with several activists praising PJM for its work maintaining electric service during January and for its response to generator retirements.

Still, the participants weren’t going to let their one shot to talk to the board — and it was almost entirely a one-way conversation — go to waste.

“Five major proposals in the capacity market in the last 12 months is a lot to digest,” said Assistant Pennsylvania Consumer Advocate Dave Evrard, who cited four changes that were approved by FERC and one that was rejected. Evrard noted that PJM had provided cost estimates on only one of the four proposals, a restriction on how demand response clears in the auction. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

“We watch somewhat nervously to see what the results of the current base residual auction will be,” Evrard said, noting that demand response offers dropped by 27% between the 2012 and 2013 base residual auctions. The question is whether the recent DR changes “[exacerbate] the decline or if that was simply an aberration,” he said.

Wil Burns, an attorney who represents environmental groups, echoed Evrard’s concerns, saying the board should not make any additional changes until it has analyzed the impact of the recent changes.

PJM’s `Inflexibility’

Brian Lipman, litigation manager at the New Jersey Division of Rate Counsel, criticized PJM for failing to discuss with stakeholders its position on a crucial capacity market rule before filing comments with the Federal Energy Regulatory Commission. PJM sided with FirstEnergy, which petitioned FERC on April 7 to change how the RTO calculates the maximum price generators can offer into capacity auctions (EL14-36).

“We didn’t find out about PJM’s position until it was filed,” he said. “That is concerning to us that we didn’t have any input into that decision.”

PJM’s “recent inflexibility” regarding rule changes “makes stakeholders worry about the future of consensus-building,” he added.

Lipman said PJM should take more time in stakeholder discussions, such as in the current discussions on the use of the Handy-Whitman building cost index in the calculation of the Cost of New Entry (CONE). “We could have been discussing that for a year now,” he said. “Decisions are happening before we have a chance to participate.” (See related story, PJM Proposes Changes to Capacity Auction Parameters for 2015.)

Role of DR, EE

Environmentalists, meanwhile, asked the board to incorporate demand response and energy efficiency into more of its planning efforts. DR and energy efficiency are “factored into one of your eight planning estimates only,” Burns said.

Yorktown Power Station (Source: Dominion Virginia Power)

For example, PJM should consider whether increased DR might allow Dominion Virginia Power to retire its Yorktown coal-fired generators as planned at the end of 2014 rather than continuing to operate temporarily to address reliability problems, Burns said.

Alison Clement, of the Sustainable FERC Project, said PJM could learn from ISO New England, where at least 90% of energy efficiency bids into the capacity market.

Rob Marmet, of the Piedmont Environmental Council, called on PJM to help states find the most effective ways to comply with pending EPA rules on greenhouse gas emissions for existing generators.

PJM Chairman Howard Schneider offered some brief remarks at the end of the session. “We value the issues you bring to us and the way you bring them to us,” Schneider said. “The relationship has improved vastly over the last several years.”

PJM CEO Terry Boston was the only other board member to offer feedback to advocates, saying he liked Burns’ idea of giving DR a bigger role in PJM’s winter reliability plans.

May 20, 2014

Monitor Suggests Price Gouging by Generators

Some generators may have taken advantage of January’s weather to boost their prices, the Market Monitor said in its quarterly State of the Market report Friday.

“The behavior of some participants during the high demand periods in January raises concerns about economic withholding,” the monitor said. “In particular, there are issues related to the ability to increase markups substantially in tight market conditions.”

The Monitor’s report cites the “markup index,” a measure of participant offer behavior. In the real-time energy market, 58% of marginal units had an average markup index at less than or equal to zero in the first quarter. But 14% of marginal units had average markups at or exceeding $150/MWh, compared to only 4% in the first three months of 2013.

In the day-ahead energy market, almost 87% of marginal units had average markups less than zero and an average markup index less than or equal to 0.03. “Nonetheless, some marginal units do have substantial markups,” the report said. Markups increased on days in January when demand was highest.

The markup index is calculated as (Price – Cost)/Price. The index ranges from -1.00, when the offer price is less than marginal cost, to 1.00, when the offer price is higher than marginal cost.

Competitive Offers Required

The Monitor said capacity resources should be required to make “competitive” offers into the energy market, an obligation that is not clear under current Tariff language.

“Selling capacity into the PJM capacity market but making energy offers daily of $999 per MWh would not fulfill the requirements of a capacity resource to make a competitive offer but would constitute economic withholding,” the Monitor explained in the 2013 State of the Market report. “This is one of the reasons that the rules governing the obligation to make a competitive offer in the Day-Ahead Energy Market should be clarified for both internal and external resources.”

The Monitor’s suggestion of economic withholding came a day after Federal Energy Regulatory Commissioner Tony Clark told PJM members that the commission had seen no evidence that market manipulation played a role in the high natural gas and electric prices in January.

In an interview yesterday, Market Monitor Joe Bowring said his staff will be interviewing generators with high markups and may refer the matter to FERC’s enforcement unit if it doesn’t receive satisfactory answers. “The Tariff requires us to refer potential enforcement matters to the commission,” he said.

January 2014 Outage Rates, Morning Peak (Source: PJM Interconnection, LLC)

Bowring said his staff is also investigating whether any generators engaged in physical withholding by improperly claiming outages. PJM saw as much as 22% of its generation out of service in early January, three times the normal winter outage rate.

Bowring said some gas-fired units took losses to operate in January. “We want to make sure that others also followed through” on their obligations, he said.

Inadequate Incentives

The Monitor’s report said the high generation outage rate in early January was an indication that the current balance of incentives and penalties is inadequate. “At present only half of capacity market revenues are at risk for failure to perform on high demand days. Gas-fired units with a single fuel are exempt from any capacity market revenue impact that results from lack of fuel outages on high demand days,” the report said.

The obligation of capacity resources to offer into the day-ahead energy market “exists regardless of whether gas procurement is difficult, regardless of whether gas prices are high and regardless of whether gas procurement is risky,” the Monitor said.

Stakeholders this month began work on developing potential winter testing requirements for generators. Consideration of incentives for generator performance and penalties for failures will be considered in a separate initiative, PJM said. (See PJM Seeks Action on Winter Lessons.)

Day-Ahead Scheduling Reserves

The Monitor also reported withholding in the day-ahead scheduling reserve (DASR) market, a problem it has cited before which worsened in 2014.

PJM uses the market to acquire supplemental, 30-minute reserves. Because the direct marginal cost of providing DASR is zero, offers greater than zero constitute economic withholding, the Monitor said.

In 2013, 12% of offers in the market exhibited evidence of withholding. The clearing price in the first three months of 2014 was $0.06 per MW, double the price for the first quarter of 2013.

About 74% of resources offered at less than $1 in the first quarter, with 11.5% of resources offered at more than $5 per MW.

The 2013 SOM report recommended incorporating the “three pivotal supplier” test in the market to prevent the exercise of market power during times of system stress, ranking it as a low priority item. PJM said it does not believe the change is warranted given the minimal impact of the market on consumer costs.

May 20, 2014

Exelon Sells Its Share of Safe Harbor Hydro

Exelon last week sold its 67% interest in Safe Harbor Hydroelectric Project, one of four run-of-the-river hydro facilities on the lower Susquehanna River, to Brookfield Renewable Energy Partners, L.P. for $613 million.

Brookfield operates 6,000 MW of generation, primarily hydro, in the United States, Canada and Brazil. It will be sole owner of the facility when the deal closes.

The deal is supposed to be finalized by the third quarter of this year, subject to regulatory approval.

Exelon inherited two-thirds ownership of Safe Harbor when it bought Constellation, parent company of Baltimore Gas & Electric. It still owns and operates Conowingo Hydroelectric Generating Station, the last dam on the Susquehanna River before it empties into the Chesapeake Bay, and Muddy Run Pumped Storage Facility, which is perched on the banks of the Susquehanna upstream from Conowingo.

Safe Harbor went into operation in 1931. It was a joint project of the two companies that would become PPL and BG&E. An affiliate of the LS Power Group purchased PPL’s share in 2011, and Brookfield bought it from LS Power in March of this year.

There are three other power-producing dams on the lower Susquehanna in Pennsylvania and Maryland. Furthest upstream is York Haven Dam, a small, 20-MW facility south of Harrisburg, Pa., owned by Olympus Power. Next is Safe Harbor followed by Holtwood Hydroelectric Plant, both between Lancaster and York Counties in Pennsylvania. Originally a 108-MW plant, PPL completed an expansion of Holtwood in 2013 that added another 125 MW.

The Conowingo dam is a 630-MW facility on the Susquehanna, between Harford and Cecil Counties in Maryland.