PJM is consolidating its rules for establishing dynamic transfers, which allow resources in one balancing authority to be operated as if they were in another BA region. Dynamic transfers can be accomplished through pseudo ties or dynamic schedules, which are cheaper and faster (see chart).
Dynamic Schedule Vs. Pseudo Tie (Source: PJM Interconnection, LLC)
The rules, spelled out in a draft white paper, are a response to PJM’s proposed capacity import limits (ER14-503). External generators with pseudo ties and confirmed firm transmission can win exemptions from the proposed limits if they also accept a “must-offer” requirement.
“We wanted to have a central place where all the options were collected,” PJM’s Sree Yeddanapudi told members at last week’s Operating Committee meeting.
Yeddanapudi said stakeholders wishing to have input on the draft whitepaper should submit comments by Feb. 28. The paper is scheduled for final review at the Operating Committee’s March 4 meeting.
Resources planning to use pseudo ties to make capacity offers in the 2017/18 Base Residual Auction must notify PJM of their intent by May 5.
Several PJM utilities released their fourth quarter earnings last week, but none made news like Exelon, which warned that it may shut down some of its nuclear generating stations if they can’t compete against subsidized renewable generators and stubbornly low natural gas prices.
“We have talked about asset rationalization in the past, and despite our best ever year in generation some of our nuclear units are unprofitable at this point in the current environment due to the low prices and bad energy policy that we are living with,” Exelon CEO Chris Crane said in a conference call.
“A better tax policy and energy policy would be the clear answer, but if we do not see a path to sustainable profits, we will be obligated to shut units down to avoid the long-term losses.”
No Hit List
Crane said there are no definite plans to shut down particular plants. Analysts, however, said some single-unit sites in Exelon’s fleet, such as Clinton Nuclear Generating Station, in Illinois, could be targeted. Another possible target is Oyster Creek Generating Station, in New Jersey, which the company already plans to decommission in 2019.
It’s not the first time Crane has mentioned shutting down plants. During the third quarter conference call last fall, he said that if wholesale prices didn’t start to rebound, Exelon could start looking at powering down some plants.
But it is the first time he’s said that units in its prized nuclear portfolio could be in the bull’s eye. Exelon traditionally has been bullish on nuclear, having built its fleet into the nation’s largest through a series of acquisitions.
Ironically, news of possible closures comes at a time when Exelon’s nuclear fleet is running better than ever. Its 10 nuclear plants in Illinois, Pennsylvania and New Jersey produced 134 million net MWh in 2013, their highest output ever, exceeding the previous record set in 2007. The plants operated at a 94.1% capacity factor.
Subsidies for renewables and slower-than-expected retirement of coal plants stacks the deck against nuclear assets, Crane said. “Our biggest push right now is at the federal and the state level to stop subsidizing in generation. That’s renewables and other sources of generation. It skews the market. It’s doesn’t give any of us the right signal — Should we be investing? Should we be shutting down? — and we think that a good policy for the competitive market is [to] let the assets compete.”
Crane’s announcement came during an analysts’ call at which the company reported an increase in fourth quarter and year-end earnings.
Fourth quarter earnings were $495 million, or 58 cents per share, compared to $378 million, or 44 cents per share a year ago. Year-end net income grew to $1.72 billion for 2013 from $1.16 billion in 2012, or $2 a share compared to $1.42 a share.
Dominion Up for Quarter, Year
Dominion Resources’ year-end earnings reports showed dramatically better numbers than a year ago, with $431 million in fourth-quarter earnings for 2013, or 74 cents a share, compared with a loss of $659 million, or $1.15 a share, a year ago.
Full-year figures showed a similar improvement, with 2013 earnings of $1.7 billion, or $2.93 per share, compared with $302 million, or 53 cents per share, a year ago.
“Dominion faced a number of challenges in 2013 and we overcame nearly all of them,” said Mark F. McGettrick, Dominion’s executive vice president and chief financial officer during a Jan. 31 earnings conference call.
Dominion’s 2012 results suffered from about $1 billion in charges associated with the sales of several fossil stations in the Midwest and Northeast, as well as a permanent shutdown of its Kewaunee nuclear plant in Carlton, Wis. and Hurricane Sandy-related restoration costs in Virginia and North Carolina.
AEP Earnings up; Ohio Revenue Eroding
AEP posted operating earnings of 60 cents per share on revenues of $3.8 billion, or a 10-cent increase over the same period last year, when it reported revenues of $3.61 billion. Year-end operating earnings were $1.57 billion, or $3.23 a share, compared with $1.5 billion, or $3.09 a share in 2012.
The fourth quarter results show a $15 million drop in operating margin at Ohio Power Co. — $590 million in 2013 compared with $605 million in 2012 — primarily from customer switching in that deregulated territory. The company said it intends to offset any continued losses in that area with increased revenue and earnings from its transmission businesses.
“Our solid financial performance in 2013, despite the loss of significant retail margins in Ohio, reflects our focus on our earnings growth strategy – investment in our core regulated operations, including our transmission business, and achieving cost savings through sustainable process improvements,” said CEO Nick Akins. “We benefited from successful regulatory proceedings in several jurisdictions, and our transmission investments delivered earnings improvement in every quarter, with transmission nearly doubling its earnings contribution in 2013.”
PPL Takes Beating on Plant Lease
PPL can blame costs associated with terminating a power plant lease in Montana for disappointing quarterly and year-end earnings, but officials said solid business unit performance offset the one-time costs.
The company’s annual profits plummeted 35% to $1.13 billion, or $1.76 a share, down from $1.53 billion, or $2.60 a share, in 2012.
Fourth quarter 2013 earnings showed a loss of $98 million, or 16 cents per share, compared with a profit of $359 million, or 60 cents per share, in 2012.
The termination of the Colstrip plant lease cost the company $413 million, or 62 cents per share, which was recorded in the fourth quarter.
Earnings from ongoing operations, which do not include the Colstrip charges, were $1.59 billion, or $2.45 per share for the year.
The company warned of lower earnings in 2014, “primarily due to lower energy margins in the Supply segment” because of lower energy and capacity prices, partially offset by lower financing costs and lower income taxes.
Members last week approved manual changes implementing PJM’s seasonal verification rules, adding a transition period for units that have not been conducting the required tests.
The rules require all steam generation units to correct their capacity ratings to reflect ambient temperatures. About half of PJM’s steam units already adjust their ratings although Manual 21 requires adjustments only for combustion turbines and combined cycle plants. The changes endorsed last week by the Planning and Market Implementation committees adds the correction requirements for nuclear, coal and oil units.
In addition, all hydro and pumped storage units will be required to perform verification tests during the summer. Previously, some of these generation owners were performing tests at other times of the year.
The MIC endorsed a transition mechanism that will allow generation owners options for addressing any capacity shortfalls that result from reduced installed capacity (ICAP) ratings under the corrected measurements.
Generation owners will have the option of seeking a capacity modification, and covering their deficiency with other assets or capacity purchases, or seeking forgiveness for shortfalls and relinquishing capacity revenues for the shortfall.
PJM sought an April 1 deadline for generation owners to make their choice for their entire portfolio.
“This was [suggested] in recognition that some generation owners are already providing adjusted results, while others haven’t,” said Stu Bresler, vice president of market operations.
Bresler resisted a request to allow generation owners to make decisions on individual units rather than their entire portfolios. “Our thought was we’d make it a one-time election,” he said. “It may seem inequitable to let GOs pick and choose what adjustments best suit them.”
Under a “friendly amendment” accepted by PJM, owners will have until April 1 for units providing capacity in delivery year 2014/15; June 1 for capacity for DY 2015/16 and Aug. 1 for DY 2016/17.
The Operating and Planning committees endorsed the following manual changes last week:
Planning Committee
Manual 7: PJM Protection Standards
Reason for Changes:Changes were required to align this manual with PJM’s protective relaying philosophy and design guidelines.
Impact: The revisions include changes to section 7 (Line Protection) and section 8 (Substation Transformer Protection).
Manual 14A: Generation and Transmission Interconnection Process
Reason for Changes: Ministerial.
Updates the list of manufacturing data sheets PJM has on file for wind turbines.
Manual 21: Rules and Procedures for Determination of Generation Capability
Reason for Changes: The changes clarify rules regarding seasonal verification of generators.
Impact: The changes clarify that intermittent resources are not required to perform seasonal verification. They also spell out that the installed capacity rating of all generators should be based on the generator’s demonstrated output under PJM summer peak load conditions, and that hydro and pumped storage units should perform their annual ratings test during the summer. Other notable changes apply to ambient conditions recording and reporting.
Operating Committee
Manual 40: Training and Service Requirements
Reason for Changes: Required annual update in accordance with NERC standards.
Impacts: Changes data retention requirement and clarifies continued training requirements for transmission operators and initial training requirements for new entities.
Adds a “human performance program” for use in PJM system operations to achieve an “event-free” culture. The program encourages a questioning attitude, peer checking methods, the use of 3-part communications, and adherence to procedures.
Members will consider relaxing metering requirements to make it more practical for residential customers to offer demand response into the synchronous reserve market under a problem statement approved by the Market Implementation Committee Friday.
Frank Lacey, of curtailment service provider Comverge, proposed the problem statement, saying DR has proven to be “a capable synchronous resource.” He said current PJM rules that require one-minute metering of synchronous resources are cost prohibitive to residential customers at $1,000 to $1,500 per meter.
PJM’s Pete Langbein said “There’s nothing today to prevent residential customers from entering the market,” though he conceded that “metering is another issue.” The question, he said, “is there a way to measure [DR response] without one-minute metering?”
Dave Pratzon, of GT Power Group, noted that only 59% of metered DR provided Tier 2 synch reserve as expected in 2013 (similar to the rate for Tier 2 generation resources). “I think it’s going to be a high hurdle to add a new class of customers that isn’t metered at all,” he said.
The MIC approved the problem statement with 12 no votes and 11 abstentions. It will hear the issue charge at its March meeting.
PJM plans to change its definition of the PJM-MISO interface to eliminate double counting that can inflate congestion calculations in market-to-market transactions.
Transactions overestimate congestion when they settle with both RTOs because both RTOs are pricing its full effect on the constraint.
Interface Pricing Flaw: Today, the full effect of transactions on the MISO M2M constraint is modeled by both RTOs.(Source: Potomac Economics)
PJM’s Rebecca Carroll officials told the Market Implementation Committee last week that PJM’s definition puts the interface too far west of the congestion and that a revised definition — comprised of 10 generator pnodes that account for 80% of tie line flows — will move it closer to the RTOs’ seam. PJM ran simulations with these 10 pnodes, using transactions from December and January, and found lower prices, though the decreases were often relatively small.
PJM officials said they would like MISO to agree to a common definition. However MISO’s Market Monitor, Potomac Economics, which identified the problem, has proposed a different solution. It would eliminate the double payment by basing the settlement entirely on the monitoring RTO’s shadow price.
If the two RTOs are unable to agree, PJM Vice President of Markets Stu Bresler said he sees no reason PJM can’t change its definition unilaterally. PJM would like to see the changes implemented by June 1, he said.
On a related issue, PJM will stop using the slice-of-system method for calculating market flows with MISO. It will begin using the marginal zone participation factor (MZPF) method, which is already used in firm flow entitlements and the interchange distribution factor.PJM and MISO are expected to jointly file the language for inclusion in their Joint Operating Agreement in March, and PJM plans to implement the changes on June 1.
Eight of PJM’s top 10 winter peaks occurred in January 2014.
Load serving entities in PJM are starting to calculate how much their bills are going to increase for a frigid January that sent load and prices to new records. And, as they made clear to PJM last week, they aren’t happy.
“We have a market that’s not functioning,” said one stakeholder during a testy session of the Market Implementation Committee Friday. “We have people who scheduled in the day-ahead market as they were supposed to and they are getting hit with these unbelievable costs.”
Carl Johnson, representing the PJM Public Power Coalition, said his members’ operating reserve charges will be “absolutely extraordinary.”
Referring to other PJM members, he added: “We’ve seen unprecedented confusion, verging on panic.”
The complaints were sparked by high natural gas prices that prompted PJM to obtain a waiver allowing the RTO to issue make-whole payments to generators whose costs exceeded the $1,000/MWh offer cap.
Generators, who want the high costs to set market clearing prices, are also unhappy.
“We cannot ever let this happen again. We have to get these prices reflected in offers,” said a second stakeholder. “You’re creating day-ahead versus real-time risk. You’re creating risk that [generators are] going to buy fuel and then not burn it.”
“Even if you don’t have deviations, the way it looks now, every megawatt that flows is going to get hit” with make-whole charges, said a third.
PJM officials were unable to provide members last week with the total energy market and uplift charges from January.
PJM Chief Financial Officer Suzanne Daugherty said that PJM, which billed $33 billion in all of 2013, billed “a lot more than 1/12th of that” during the month. Eight of the top ten winter demand peaks in PJM’s history occurred during January.
Members won’t see the full impact of January in their bills for months because of a lag in demand response data. The debate over the future of the $1,000 price cap will likely last far longer.
Windfall vs. Market Integrity
The Federal Energy Regulatory Commission, which approved PJM’s request to allow make-whole payments for generators whose costs exceeded the cap, has yet to rule on PJM’s request to lift the cap altogether through March 31.
That would allow high-cost gas generators to set clearing prices, which PJM and generators say is essential to preserving the integrity of the RTO’s single price energy market, in which the marginal unit sets the price for all generation operating.
Load serving entities say lifting the cap would result in an unjust windfall for the vast majority of generators, whose costs never approached $1,000/MWh.
PJM said the make-whole payments would affect about 6,800 MW of mostly older combustion turbine generation, whose prices could be as high as $1,500 to $2,000/MWH.
“Since this generation is the least efficient on PJM’s system, much of it rarely or never operates, and as little as 50 to 100 MW may be all that is operating and bearing these high costs,” the Maryland Public Service Commission said in arguing against lifting the cap. “Shockingly, PJM has requested that the entirety of the 135,000 to 140,000 MW required to operate to provide service during extreme cold weather events receive this price spike-induced pricing.”
Rationale for Cap
In a 2002 rulemaking, PJM noted that the cap was at least five times the marginal cost of production of its highest cost units, and said it “serves to permit scarcity pricing while preventing the exercise of market power that would result if the cap were higher.”
In arguing to lift the cap for the remainder of the winter, PJM told FERC that continuing to rely on make-whole payments “falls short of Commission policy, and PJM’s fundamental market design, that clearing prices should reflect the marginal costs of the last resource needed to clear the market.”
The RTO cited a prior FERC ruling saying that uplift costs must be minimized because they “fail to send clear market signals” needed to encourage new market entry.
PJM vs. NYISO Approach
The Electric Power Supply Association, which represents generators, asked FERC to not only allow PJM’s market-clearing request, but also to impose it on NYISO. “It is time to move past Band-Aid fixes for persistent structural problems in these markets,” EPSA said, calling the price caps “outdated.”
The New York ISO also won a make-whole waiver to its $1,000 price cap, through Feb. 28. But unlike PJM, it did not seek permission to let units with costs over the cap set clearing prices. That, NYISO said, would lead to “over-compensating” generators.
DC Energy LLC, which trades financial transmission rights in PJM, supported EPSA’s request, saying a disparity in treatment between the two regions would lead to “unwarranted interface flow and congestion in the NYISO-to-PJM direction” that could lead to “even more generators being dispatched and compensated out-of-market in NYISO.”
Criticism of PJM Operations
At Friday’s MIC meeting, members also pressed PJM staff to commit to full after-action review similar to what it provided regarding the September heat wave.
“I would hate for PJM staff to be disconnected from the emotional state in the market created” by January’s events, one stakeholder said. “That would come across as tone deaf… I think this does really warrant all hands on deck.”
Members also complained that poor load forecasts led to excessive uplift charges.
Emergency demand response was called on January 7, 8, 27 and 28, although the Jan. 8 dispatch was cancelled when load came in lower than expected.
PJM officials have said their load forecasts in early January were inaccurate because there was no historical record for the kind of RTO-wide cold experienced during the polar vortex.
“Based on the waiver and tariff it’s tough to put those costs anywhere but BOR,” said Adam Keech, director of wholesale market operations.
Costs due to operator actions to preserve reliability — “conservative operations” — will be assessed to real-time load and exports. Uplift resulting from deviations between day-ahead and real-time schedules are collected from all those with deviations including increment offers and decrement bids.
PJM officials said the make-whole payments will be recovered through Balancing Operating Reserve (BOR) charges in bills to be sent in February. Because DR providers have 60 days to submit metered data, uplift charges from the DR calls won’t show up in bills until March and April.
Market Manipulation?
Opponents of lifting the caps urged FERC to conduct fact-finding before issuing a ruling in the case, in part to determine whether market manipulation played a role in the high gas and power prices.
The Maryland PSC said the commission should investigate PJM’s claim that inefficient combustion turbines with heat rates of 14,000 to 18,000 Btu/kWh were needed to provide service during the cold.
“PJM forced outage rates this winter have exceeded 20% where they normally do not exceed 8%, an increase that affects almost 20,000 MW of generation,” the PSC wrote. “…Can the commission rule out the potential that some of this generation has been withheld in order to drive market prices higher or is suffering outages for other impermissible reasons?”
Washington Gas Energy Services, Inc., a retail gas and electricity marketer, said PJM’s dispatch during the cold “left gas generators having to bid `whatever it takes’ to buy the gas in the open market…When electricity generators become gas buyers with no alternatives, the gas sellers quickly raise prices as high as possible. With the $1,000/MWh cap in place, there is at least some resistance to the gas prices exceeding $100/MMBtu.”
Maryland regulators also noted there was a disparity in gas prices on pipelines serving PJM generators. While PJM cited prices at two city-gates on the TRANSCO pipeline that could push generators’ costs above the cap, TETCO’s pipeline was offering pricing that allowed CTs to produce power at costs below the cap, Maryland said.
Impact on retail marketers
In addition to uplift charges, market participants also will be assessed for more than $2 million to cover defaults by two power retailers that were unable to cover the price spikes. CCES LLC, operating as Clean Currents, defaulted on $1.6 to $1.8 million while People’s Power & Gas LLC owes PJM $400,000 to $600,000.
PJM will ask the Board of Managers at its Feb. 12 meeting to approve an assessment on members to collect the defaults. The allocations will show up in March bills.
Exempt are associate members, municipal members that have received waivers, Emergency and Economy Load Response and ex-officio members, such as state consumer advocates.
The assessment formula spreads 10% of the default over all non-exempt members — about $250 to $350 per member. The remainder will be assessed based on total gross activity for the month of the default and the two previous months.
While PJM isn’t aware of any of other retailers in financial distress, Daugherty said she couldn’t promise “there’s no one else.”
Most at risk are retailers that sold power on fixed-price contracts, particularly in states that don’t allow suppliers to pass through costs attributable to changes in market rules. In Pennsylvania, “fixed means fixed” for the term of the retail agreement, retailer Ethical Electric said in a protest to the PJM waiver request.
State regulators have warned customers to review their contracts. Many variable-rate plans do not contain price ceilings.
The Retail Electric Supply Association sided with generators supporting PJM’s call for allowing $1,000-plus generation to set clearing prices, saying that its members can hedge energy prices but not uplift costs.
The group includes retailers that are part of larger companies that own generation, including PPL, GDF Suez, AEP and Exelon, whose generation affiliates would benefit from high market clearing prices.
The review of proposed solutions to the Artificial Island transmission stability problem is taking longer than expected and the selection of the winner could be months away, PJM officials told the Transmission Expansion Advisory Committee last week.
An engineering consultant has completed a preliminary constructability review of the 26 potential solutions, which range in cost from $100 million to $1.5 billion.
Eight proposals are among those considered favorites to win the bid, including five that would add a 17-mile 500kv line that parallels an existing 500kv line from Red Lion to Hope Creek.
Three other projects would cross the Delaware River to the Delmarva Peninsula with a 230kv line and run to a new substation or expanded Cedar Creek substation. Two of the proposals would run a submerged line in the river bed and the other would run the line above the water.
Much of the analysis has focused on combining the lower cost proposals with static VAR compensators to provide reactive support. Other factors being considered include the need to obtain right of way, environmental impacts, and the number of planned outages needed during construction.
The front-running proposals range in cost from $110 million to $270 million, and will take from 42 to 111 months. While the relatively modest cost of these projects is an attractive feature for PJM, Paul McGlynn, general manager of system planning, said there is still plenty of evaluation to be done.
“We have focused a lot of our attention on the lower cost projects, but I wouldn’t say others are off the table,” he said.
McGlynn said optimism that PJM staff could make a project recommendation to the PJM board in February has faded.
Artificial Island is the home of the Salem and Hope Creek nuclear plants in Hancocks Bridge, N.J. Five utilities and three independent developers made proposals in PJM’s first competitive transmission project under FERC Order 1000.
PJM provided members a glimpse last week of the new visualization tools that will soon be available to transmission operators as a result of the deployment of synchrophasors.
The Real Time Dynamics Monitoring System will provide wide area situational awareness data to help analyze system performance & events. It will include several measures of grid dynamics, including phase angle differences (grid stress); small signal stability (oscillations & damping); frequency instability; generation-load imbalance; power-angle sensitivity and power-voltage sensitivity.
TOs will be offered training on the tool Feb. 28.
PJM officials said they will consider in the System Operations Subcommittee whether generator owners, which are being required to installed synchrophasors, should also have access to the system.
Members endorsed rules describing when economic demand response is eligible for compensation, over the objections of some demand response providers, who said they are unfair.
The changes to Manual 11: Energy & Ancillary Services Market Operations specify that economic DR will be compensated at full Locational Marginal Pricing for “demand reductions that are executed in response to the real‐time and/or day‐ahead LMP or as dispatched by PJM and that are not implemented as part of normal operations.”
Excluded will be “load reductions from normal operations that would have occurred without PJM dispatch, or that would have occurred absent PJM energy market compensation.”
The changes, meant to clarify rules that took effect in April 2012 to comply with FERC Order 745, won 110 votes in support with 22 no votes and 18 abstentions.
Pete Langbein, of PJM, explained that some electricity customers manage their resources in a sophisticated manner that can lead to inflated settlement costs.
“This is just consistent with the way we’re interpreting the Tariff now,” Langbein said. “This is not crafted to have some mysterious meaning behind it.”
One representative said his clients oppose “PJM speculating” about DR participants’ intent.
Frank Lacey, of curtailment service provider Comverge, set up a hypothetical situation in which a retailer dims its lights or turns off escalators in response to day-ahead pricing. “If that was done for the last 10 years, now that can’t be offered into the energy market as a load reduction” under PJM’s interpretation, he said.
John Webster, of Icetec Energy Services, said the change “introduces a lack of transparency.” He said the new language could be “discriminatory based on the level of [customer] sophistication.”
Despite the reservations, stakeholders endorsed the Manual changes with 83 percent support. It will go to the MRC for consideration later this month.
