Dynegy’s purchase of Energy Capital Partners’ New England power plants will immediately make it a major participant in a market where it has been a bit player.
Dynegy’s only presence in ISO-NE is the gas-fired 540-MW Casco Bay Energy Facility in Maine. The company is acquiring four combined-cycle gas generators in Massachusetts and Connecticut totaling 1,902 MW, in addition to the Brayton Point station in Massachusetts, a 1,510-MW coal-fired power plant that is slated for closure in May 2017.
Dynegy said it will retire Brayton Point on schedule. But for the two years that it will operate the plant, Dynegy will rival Exelon at the top of the generation market-share rankings in New England.
Calpine announced yesterday that it is purchasing Exelon’s 809-MW Fore River generating station in Massachusetts. The deal, expected to close in the fourth quarter, would make Calpine the eighth-largest generator in New England, up from 13th.
Including all of the ECP plants, Dynegy will have about 200 MW more than Exelon once the Fore River sale is complete.
Excluding the coal plant, the ECP acquisition will put Dynegy in fifth place, behind Exelon, Dominion Resources, GDF Suez Energy and NextEra Energy. About 10% of Dynegy’s portfolio will be located in New England.
ISO-NE said it is planning for the loss of Brayton Point with a study to identify transmission upgrades needed to move power into southeastern Massachusetts and Rhode Island.
“Private investors can also come forward with proposals for generation or demand-side resources that could address the reliability concerns,” ISO-NE spokeswoman Marcia Blomberg said. “If the needed transmission upgrades or resource proposals aren’t in service by the time that Brayton Point retires, the ISO and transmission owners will have special transmission operating plans in place to deal with unexpected transmission or generation outages.”
Members deadlocked last week on changes to capacity market parameters, with none of five proposals winning a supermajority.
As a result, the Board of Managers will decide for itself whether to seek Federal Energy Regulatory Commission approval for PJM staff’s proposed changes, including a shift in the shape and position of the capacity demand curve.
The board must file changes with FERC by Oct. 1. Changes approved by the commission would be implemented for the 2015 Base Residual Auction (BRA).
Not Even Close
Stakeholders nearly reached consensus in PJM’s last Triennial Review of the market parameters in 2011. This time around, it wasn’t close.
In meetings of the Capacity Senior Task Force, members did reach agreement on several issues, including the use of a combustion turbine as the reference technology for calculating the cost of new entry (CONE). They also agreed to use data from the U.S. Bureau of Labor Statistics to raise CONE for inflation, replacing the proprietary Handy-Whitman index.
But agreement was nowhere to be found on changes to the variable resource requirement (VRR) curve.
Proposals by PJM staff, Public Service Enterprise Group (Package B) and Dayton Power and Light (Package I) all received less than 50% support in sector-weighted votes of the Markets and Reliability Committee, with only the Transmission Owners and Generation Owner sectors showing heavy support.
Virtually all members of the Electric Distributors and End User Customer sectors opposed the proposed changes and supported the status quo, which received a 56% vote overall.
A proposal to use the PJM plan but keep the current energy and ancillary services offset also failed.
Unconvinced
Load representatives said they were not convinced by arguments from PJM staff and the Independent Market Monitor that changes to the VRR curve were needed to prevent the RTO from falling short of its one-day-in-10-years loss-of-load expectation.
“We came dangerously close to the edge in January,” when the RTO nearly ran short of generation, FirstEnergy’s Jim Benchek said.
Exelon’s Jason Barker said the changes are needed to stabilize the capacity market and prevent retirements of “at-risk” coal and nuclear capacity.
But load representatives said PJM had failed to make its case for the changes, which Walter Hall of the Maryland Public Service Commission said could increase customers’ capacity costs by up to 50%. Hall said the PSEG and DPL proposals would likely increase capacity costs by more than the PJM proposal, which would have increased capacity revenues in the last three BRAs by $1 billion to $1.7 billion, according to a PJM simulation.
Carl Johnson, representing the PJM Public Power Coalition, said changing the curve was inappropriate now, at a time when PJM is also proposing a “redefinition” of what capacity is. (See related story, Reaction Muted as PJM Pitches New Capacity Product.)
PJM is asking “us to buy more of something we don’t have an understanding of,” Johnson said. “It’s not that we oppose any shift in the VRR curve for all time.”
PJM Executive Vice President for Markets Andy Ott said the proposed curve change “doesn’t mean we will procure more [capacity]. It means increased stability of the investment signal.”
Convex Curve
The PJM proposal would shift to a convex-shaped curve from the current concave shape. It would also shift the curve recommended by The Brattle Group, PJM’s consultant, to the right by 1%.
Additionally, it would reduce CONE values from the status quo, eliminate CONE area 5 and move Dominion into area 3.
The PSEG and DPL proposals would use most of the PJM proposal. The PSEG proposal would shift the recommended curve by 2%, increase CONE values for PJM’s five areas by 39% to 58% and increase the after-tax weighted cost of capital to 13.5% from PJM’s proposed 8%. The DPL proposal would move the curve by 2.5%, essentially eliminating the “holdback” that the Market Monitor has cited as one of the causes of “price suppression” in the capacity market. (See related story, Monitor: Resist Subsidies, Don’t Retreat from Markets.)
Ott said staff was likely to recommend its proposals regarding the shape and location of the VRR curve for consideration by the board. “I don’t have any reason for hesitating on those recommendations,” he said.
However, he said staff would reconsider its proposal to replace the current backward-looking energy and ancillary services offset with a forward-looking measure. While some stakeholders praised the concept, they said it needed more vetting before being included in a FERC filing.
There were seemingly as many questions as answers Friday as PJM met with stakeholders to discuss its plan for a new “Capacity Performance” product to improve reliability on peak demand days.
PJM officials said they were willing to change — or had not decided on — numerous elements of the proposal.
“Staff was being very clear that they are open to and looking for feedback,” said Nancy Bagot, vice president for regulatory policy for the Electric Power Supply Association, after the four-hour meeting. “I think it’s too early for us to have formed any opinions — even to ask good questions. I do get the feeling that a lot could change.”
PJM proposed a series of changes to the capacity market on Wednesday, the centerpiece of which is the addition of the Capacity Performance product. It would supplement existing Annual Capacity (renamed Base Capacity), Extended Summer and Limited Demand Response offerings. (See PJM: New Capacity Product Needed for Reliability.)
The new product would include generation, demand response and energy efficiency providers that can guarantee their availability during Hot and Cold Weather Alerts and Maximum Emergency Generation Alerts. The resources would need to demonstrate they can produce their committed installed capacity for 16 hours for each of three consecutive days.
Enhanced Liaison Committee
PJM said they will invoke a never-used “Enhanced Liaison Committee” process so that the new rules can be filed with the Federal Energy Regulatory Commission in time for the winter of 2015/16. The process was developed in 2011 to allow members to provide input on issues for which consensus is unlikely and the Board of Managers acts independently. (See PJM to Hike Penalties, Incentives to Improve Winter Reliability.)
While the board will have the last say on what is submitted to FERC — and protests are almost certain, regardless of the final package — PJM would like to eliminate as many points of conflict as possible beforehand.
Executive Vice President for Markets Andy Ott said that officials were willing to adjust the metrics used to determine requirements and penalties and how the new rules would apply to vertically integrated utilities.
Although no one voiced overt opposition to the proposal Friday, one stakeholder representing consumers raised concerns over market power.
Potential Changes
One item that may be changed is the use of installed capacity (ICAP) rather than unforced capacity (UCAP) in determining requirements and penalties.
ICAP represents the plant’s maximum output during summer; UCAP is the ICAP value minus its recent forced outage rate (EFORd).
FirstEnergy’s Jim Benchek said the rule could be unfair to pump storage that has high ICAP values but lower offer amounts.
Ott said PJM officials would consider a change, agreeing with one questioner that the choice between the two measures was a “jump ball.”
“In the [proposal] they put an ‘I’ instead of a ‘U,’” Ott said.
Distribution of Penalty Revenues
Ott said staff may also reconsider how the penalty rules would apply to vertically integrated utilities and load-serving entities with Fixed Revenue Requirements.
PJM plans to distribute penalty revenues to load, unlike New England, which distributes them among “overperforming” resources.
Dave Pratzon of GT Power Group said distributing penalties to load could give load-serving entities with generation less incentive to improve performance than independent generators, who have no way to recover any of their penalties.
“It seems like you’re taking money out of one pocket and into another,” said Pratzon, whose company represents generators.
Ott agreed. “We have to deal with those who are indifferent to costs coming out of the capacity market,” he said.
Outside Management Control
Officials said they also plan to clarify the RTO’s definition of force majeure. The proposal allows no exclusions for force majeure “at this point,” PJM Chief Economist Paul Sotkiewicz said.
PJM has proposed changing current rules, which allow a generator to remove outages defined as “outside management control” from the forced outage rate that determines the capacity it can sell.
“The performance penalties ultimately adopted as part of this proposal will apply to generation resources regardless of the reason for a forced outage, and therefore it would be inconsistent to remove outside management control outages from the EFORd calculation,” PJM’s proposal said.
Penalties, ‘Unbounded’ Risk
PJM would set the hourly penalty for Performance Capacity resources to the LMP multiplied by the number of megawatts the unit failed to produce.
The penalty would apply to whichever was lower: the quantity of MWs scheduled by PJM or the unit’s ICAP. A unit with a 100-MW ICAP commitment that was dispatched by PJM to produce 75 MW but produced only 25 MW would be penalized for the 50-MW difference.
PJM said the calculation is based on an ISO-NE model already approved by FERC.
PJM would set an annual cap, limiting the penalties applied to a Capacity Performance resource to 2.5 times the resource’s capacity revenues for the year. Penalties for Base Capacity resources would be limited to 1.5 times capacity revenues.
“Whenever we put too much risk on the seller at the plant, it shows up in cost. We could create so much unbounded risk that we could all be worse off when all is said and done,” said Mark Scott, a consultant for Old Dominion Electric Cooperative. “You want some pain, but you don’t want to kill them.”
Ott said officials believe the penalty has to be severe enough that resources that fail to perform suffer financial pain — not just the loss of capacity revenues.
“It has to be able to go negative in our opinion. Otherwise the worst-case scenario is I lose my capacity payment and I can be a price taker in the capacity auction and roll the dice” on getting dispatched.
But Ott said the 2.5 penalty multiplier could be changed. “We had to put a number out there. We get it. … That number is moveable.”
PJM may also expand on a proposal allowing generating companies to avoid penalties by offsetting an outage at one unit with production by another in their portfolios. Asked whether generators could replace the shortage through bilateral trades, Ott said, “I can’t think of a reason not to allow it. … We certainly can think about it.”
Scott asked why PJM was attempting to solve all the reliability issues through the capacity market rather than also using the energy market.
Ott said many generation owners would have to make capital investments to their plants to meet the Performance Capacity requirements. “It would be a forward investment. Therefore it made sense that there be an opportunity to recover that through capacity,” he said.
Risk Premium
One issue that Sotkiewicz acknowledged would be controversial is the inclusion of a risk premium in addition to the current 10% adder allowed for “hard-to-quantify” costs.
“Given the change in the penalty structure, we think it’s appropriate to include an explicit risk premium,” he explained.
PJM says the risk premium will ensure “symmetry between risk and reward” for Capacity Performance resources. PJM proposed the premium be based on the 7% pool-wide EFORd, multiplied by the historic average of Hot and Cold Weather Alert hours, multiplied by the average real-time LMP at the generation bus.
Using the 7% EFORd ensures generators will have the incentive to make the operations, maintenance and other investments “to achieve significantly better performance than PJM has historically observed during peak periods,” PJM said.
American Electric Power’s Dana Horton asked whether his calculation of the premium — about $10/MW-day — was accurate. “Yes, that is the order of magnitude,” Sotkiewicz said.
Market Power Concerns
James Wilson, a consultant to state consumer advocates, said he was concerned that owners of large generation portfolios will have incentives to withhold the Capacity Performance Product, choosing to offer part of their portfolios only as the Base Capacity product. “That’s one topic you need to give a lot more attention to,” he said.
Current rules require capacity resources to offer into the day-ahead energy market. PJM said it’s “an open question” how that obligation should apply to the new product.
“If all capacity were required to satisfy the criteria for the Capacity Performance product, then the current must-offer requirement would make sense,” PJM’s proposal says. “However, if there are multiple products, it is not clear how the must-offer requirement should apply.”
“At a minimum, the must-offer requirement to offer into the capacity market as one type of product or another should apply. But with multiple products, market incentives and competitive forces should then take over with resources offering in the product area that will result in the most surplus (clearing price minus the cost of providing the product).”
Stakeholders will meet again on Sept. 11 to further discuss the proposal.
The Bureau of Ocean Energy Management cut the size of a proposed offshore wind field near Kitty Hawk, N.C., last week and located it farther off the coast. The agency previously identified the proposed area for commercial wind generation at 877,837 acres, but the new map shows it reduced to 122,405 acres. OEM also relocated the area from six miles offshore to 27 miles.
The decision was a victory for groups that had opposed the initial plans, including the town of Kitty Hawk, the National Park Service and the World Shipping Council. Identifying the lease area is one of the first stages of commercial wind development. No confirmed construction plans have been announced.
US Wind won two leases for nearly 80,000 acres of wind-energy plots off the Maryland coast. The Bureau of Ocean Energy Management last week awarded US Wind the rights to the North Lease area (32,700 acres) and South Lease Area (46,970 acres.) Together, they are known as the Maryland Wind Energy Area, which lies about 10 miles off Ocean City. US Wind outlasted two competitors with its provisionally winning bid of $8.7 million. It has a year to file a site assessment plan with the bureau. If approved, it will have 4.5 years to submit a construction plan. US Wind is a subsidiary of Italian renewable energy company Renexia.
The nation’s urban air is getting cleaner, thanks to the Clean Air Act Amendments of 1990. The Environmental Protection Agency said last week that the Urban Air Toxics Report shows a 66% reduction in benzene, 60% reduction in mercury in coal-fired power plants and an 84% decrease in lead. “This report gives everyone fighting for clean air a lot to be proud of because for more than 40 years we have been protecting Americans – preventing illness and improving our quality of life by cutting air pollution – all while the economy has more than tripled,” said EPA Administrator Gina McCarthy.
The Federal Energy Regulatory Commission allowed a company that wants to build a transmission line from Oklahoma to Tennessee to negotiate power rates and bilateral agreements. Clean Line Energy said FERC has approved its planned 700-mile “Plains & Eastern” line. The direct-current transmission line would carry wind power from the Oklahoma Panhandle to western Tennessee, connecting with the Tennessee Valley Authority’s system. “This confirms what we’re already doing with our open solicitation from those wanting to use our line and we can now move forward with specific negotiations,” Mario Hurtado, co-founder and executive vice president of development for Clean Line, said last week.
Journalists Claim EPA Blocking Access to Scientists
A coalition of journalists and scientific groups says the Environmental Protection Agency is blocking media access to independent science advisers, according to a letter the group sent to EPA chief Gina McCarthy. The group complains that the agency requires that members of its Science Advisory Board pass on media requests to the EPA press office, which usually doesn’t allow interviews of the scientists. “The EPA wants to control what information the public receives about crucial issues affecting Americans’ health and well-being,” Society of Professional Journalists President David Cuillier said. “The people are entitled to get this information unfiltered from scientists, not spoon-fed by government spin doctors who might mislead and hide information for political reasons or to muzzle criticism.”
The agency denied blocking access. EPA spokeswoman Liz Purchia said in a statement that “transparency and openness are key operating principles” for the agency, noting that the Science Advisory Board meetings and documents are accessible to the public and the press. “There are no constraints on members of the SAB testifying or speaking to the public in their personal or professional capacity, or taking questions related to administrative SAB matters,” she said.
The U.S. ranks second in installed wind capacity, enough to meet 4.5% of total electrical demand, according to a Department of Energy report issued last week. The DOE says the U.S. wind-energy market remains strong, and that the U.S. could double electricity generation from renewable sources by 2020. The reports put total installed wind capacity at 61 GW. China ranks first with 91 GW.
The Army is forming a permanent office to identify, award and complete renewable energy projects, it said last week. Amanda Simpson, executive director of the Army Energy Initiatives Task Force, said the Army will have 25 renewable energy projects under way next year. The Task Force will become the Army’s Office of Energy Initiatives in October and aims to get 1 GW of renewable energy online by 2025. Simpson said there are already 13 projects in development, including an 18-MW solar plant at Fort Huachuca, Ariz., and 90 MW of solar at Fort Stewart, Ga.
Dynegy, which emerged from bankruptcy just two years ago, announced Friday it will nearly double its capacity with the purchase of about 12,400 MW of generation from Duke Energy and private equity firm Energy Capital Partners.
If approved by regulators, the deal would rank Dynegy just behind Calpine, the third-largest competitive generator in the U.S.
Dynegy would gain about 9,000 MW in PJM, boosting it to more than 10,700 MW and eighth in generation share in the RTO.
The $2.8 billion Duke agreement includes 11 generating units in the Midwest and Duke Energy Retail, Duke’s competitive retail energy business in Ohio, Pennsylvania and Michigan — adding to Dynegy’s existing retail business in Illinois. The $3.45 billion deal with Energy Capital Partners is for 10 units in the Midwest and New England.
Growth in New England
In addition to making it a major player in PJM, the transaction will give Dynegy a larger foothold in ISO-NE.
Dynegy could briefly dislodge Exelon from the top of the New England generation market share rankings as a result of its ECP acquisition and Calpine’s announcement yesterday that it will buy Exelon’s Fore River Generating Station, an 809-MW combined-cycle plant near Boston, for $530 million. (See related story, Dynegy Becomes New England Player Overnight.)
Dynegy would drop to fifth after the scheduled 2017 retirement of ECP’s 1,510-MW Brayton Point coal generator.
“The addition of these portfolios transforms Dynegy by adding considerable scale in the PJM and New England markets,” Dynegy President and CEO Robert Flexon said. Dynegy said it expects the deals to close by the end of the first quarter of 2015.
Investors reacted favorably, with Dynegy’s shares jumping 18% on the news before settling at $32.58 Monday, an 8% gain.
Merchant Generation, Retail Sales
Dynegy currently has about 13,200 MW of generation: 7,042 in MISO; almost 2,700 in CAISO; 1,780 in PJM; 1,064 in NYISO; and 540 in ISO-NE.
Dynegy is betting on two sectors — merchant generation and retail sales — that other players have been exiting or de-emphasizing.
Duke signaled its intention to pull out of the merchant generation business in February, days after the Public Utilities Commission of Ohio refused the company’s request to bill regulated customers $729 million to make up for a shortfall between its plant operating costs and plunging wholesale power prices.
PPL announced in June it would spin off its generation unit in a deal with Riverstone Holdings, leaving it with a pure rate-regulated business model.
Exelon agreed in May to buy Pepco Holdings Inc. for $6.83 billion, seeking to increase its regulated rate base.
Duke is not alone in souring on the competitive retail business. Dominion Resources agreed in March to sell its business serving 600,000 retail customers to NRG Energy. FirstEnergy Solutions said this month it will stop pursuing sales to residential and small and mid-size commercial customers.
Dynegy, however, sees retail sales as a “natural hedge for our generation,” spokeswoman Katie Sullivan said.
Back from Bankruptcy
Founded in 1984 as a gas trading company, Dynegy has had a turbulent history. It survived several Enron-era scandals, near-bankruptcy in 2002 and attempted takeovers in 2010.
In its high-flying days, it owned plants in a dozen states and six foreign countries. When it emerged from bankruptcy in October 2012, it was down to 16 power plants in six states.
The company began to rebuild its merchant fleet last year, buying St. Louis-based Ameren Corp.’s five coal-fired plants in Illinois.
Dynegy is betting on economies of scale with the Duke and ECP acquisition. It expects to realize fuel cost and maintenance savings of $40 million and operational management savings of $200 million. It says these deals will drop its overhead cost 35%, from $1.67/MWh to $1.10/MWh.
The deal will also allow it to take advantage of a $3.2 billion net-operating-loss carry-forward that it says will yield $480 million in tax savings on future earnings.
Its free cash flow yield on the new assets will be 36%, the company said, refilling its coffers for perhaps more acquisitions in the future.
The company will finance the acquisitions with $5 billion in unsecured notes and $1.25 billion in equity and equity-linked securities, including $200 million in common stock issued to ECP.
Bullish on PJM, New England
Dynegy said it is bullish on both the PJM and ISO-NE markets. Plant retirements will translate into tighter reserve margins and higher energy and capacity prices, it says, particularly in New England.
“New England is not getting any new builds,” Flexon said in a conference call with stock analysts Friday. Retiring Brayton, as the current owners had planned, “puts pressure on that marketplace also.”
Capacity payments represent 11% of Dynegy’s current gross margins. With the new acquisitions, capacity payments will represent 25%, as it more than quintuples its generation in PJM and ISO-NE.
MISO’s share of Dynegy’s total generation will fall to 29% from 53% as a result of the expansion in PJM and New England. But Flexon was also optimistic about the company’s prospects in the Midwest, saying 2015 through 2017 “should be a really peak time for the MISO marketplace” due to plant retirements.
Fuel Diversity
Once Brayton Point is closed, Dynegy will have reduced the share of coal-fired generation in its fleet to 45% from 53%. The company said the 3,800 MW of coal-fired plants it is acquiring, excluding Brayton Point, are all “environmentally compliant.”
About 7,000 MW of the acquisition are natural gas-fired plants, including 5,000 MW of modern, low-heat-rate, high-capacity-factor combined-cycle plants.
Julien Dumoulin-Smith, a utility analyst at UBS Securities, said the deals are positive for Dynegy’s long-term growth and will provide protection from a takeover by another company.
“The transaction propels Dynegy to among the largest IPPs in the industry, likely no longer a take-out target,” he said. “Strategically, the deal adds substantial diversification to a portfolio both overly levered to the MISO market, as well as some further diversification from coal.”
Dumoulin-Smith didn’t see much problem getting regulatory approval for the deals. “As for execution of the transaction, we do not anticipate any significant hurdles, with only very limited market overlap across any of the contemplated portfolios.”
PJM stakeholders often divide into factions, but the split that emerged in a Members Committee discussion Thursday had nothing to do with long-running battles over demand response, capacity market rules or uplift. Rather, the issue was where these battles should be fought.
For the last two months, Members and Markets and Reliability committee meetings normally held at the Chase Center in Wilmington, Del., were relocated to PJM’s Conference and Training Center in Valley Forge, Pa., to avoid traffic tie-ups resulting from repairs to a highway bridge in Wilmington. With the bridge now reopened, the two senior committees are scheduled to return to Wilmington in September.
But some stakeholders — and PJM staff — would like to abandon Wilmington and hold the meetings in Valley Forge, where lower-level meetings have been held since the CTC was completed in July 2012.
Supporters of the CTC location cited its proximity to PJM staff, only some of whom regularly attend the MRC/MC meetings. Chief Financial Officer Suzanne Daugherty said PJM spends about $150,000 annually to hold meetings at the Chase Center, not including staffers’ mileage payments and travel time.
Others, particularly those whose companies are based south of Philadelphia, said Wilmington was preferable because of its location near an Amtrak station. Valley Forge lacks mass transit and requires those outside the Philadelphia area to make a long drive or rent a car after flying or taking a train into the city.
Ed Tatum of Old Dominion Electric Cooperative said the trip to Valley Forge can take him at least five hours by car. Moving all meetings to Valley Forge, he said, could result in “a cottage industry of people who live in this [Philadelphia] area and only get to the home office once a month.”
Tatum said any decision should consider not only PJM’s costs but members’ travel costs.
Lisa Moerner of Dominion Resources said “there is no good option to get to Valley Forge” from her Richmond, Va., base. “Wilmington is much easier for those coming from the south,” she said.
Marji Phillips of Direct Energy suggested using the Cira Centre, next door to Philadelphia’s 30th Street Station.
PJM officials said they would explore their options, including one suggestion that it offer shuttle buses to transport members to the CTC from a nearby train station.
The Markets and Reliability Committee approved the following with little debate or discussion on Thursday.
Manual Changes Approved
Manual 12: Balancing Operations. Updates Section 4.5, “Qualifying Regulating Resources,” for clarity, accuracy and consistency, including a description of current regulation testing procedures; consolidates “PJM Actions” from previous subsections into Section 4.5.
Manual 14B: PJM Region Transmission Planning Process. Adds language describing easily resolved constraints for Capacity Emergency Transfer Limits (CETL) to match that in the Tariff. (See MRC / MC Approvals.)
The committee approved Operating Agreement revisions defining supplemental transmission projects, as recommended by the Regional Planning Process Senior Task Force. (See PJM’s `To Do’ List.)
Settlement, Credit Changes
Members OK’d manual and Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data. The changes are intended to address problems with reporting output for non-utility generators. (See PJM MIC OKs Settlement, Credit Changes.)
The committee also approved manual and Reliability Assurance Agreement changes recommended by the Market Settlements Subcommittee allowing EDCs to submit corrections to Peak Load Contribution and Network Service Peak Load assignments until noon on the next business day. The changes are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)
Members Committee
The Members Committee approved a “back stop” mechanism for acquiring black start services through transmission providers when PJM solicitations fail to obtain service for a zone. Members also approved minor Tariff and manual changes relating to the compensation of black start units. Both sets of changes were approved by the MRC July 31. (See MRC Briefs.)
PJM has consistently had among the highest uplift rates among RTOs and ISOs, according to a Federal Energy Regulatory Commission report released last week.
The FERC staff report found that PJM’s uplift ranked second among organized markets from 2009 to 2013, with charges increasing from about $0.50/MWh to more than $1/MWh over that period. Only NYISO was consistently higher.
The report also found that:
Some resources and regions, such as PJM’s Dominion-Virginia and Delmarva zones, receive a disproportionate volume of uplift payments. PJM had among the highest concentrations of uplift payments, with 19 generating plants receiving more than $10 million and 33 receiving at least $5 million in 2013, the 33 representing 82% of total uplift for the year.
Uplift payments are closely related to differences between coal and natural gas prices and divergences between day-ahead and real-time prices.
The volatility of uplift costs varies across RTOs and ISOs. It has risen in three of the five markets studied, including PJM.
A lack of transparency on the location of uplift credits and the reasons they are incurred are inhibiting market participants from making investments that could reduce the costs.
Sept. 8 Workshop
The report was intended to frame issues for discussion at FERC’s Sept. 8 workshop on uplift payments in energy and ancillary service markets (AD14-14).
FERC had said in June that it would convene a series of workshops to consider rule changes regarding uplift, price caps and other issues affecting price formation in PJM and other RTOs and ISOs.
The commission said its inquiry was prompted by comments made at recent technical conferences on capacity markets and the grid’s response to the recent severe winter. The workshops will consider ways to address limitations in RTO market software that prevent RTOs from modeling all system parameters, such as voltage constraints and generator operating constraints. (See FERC to Tackle RTO Uplift, Price Formation.)
Among those scheduled to speak at the conference are PJM Market Monitor Joe Bowring; Stu Bresler, PJM vice president of market operations; Jason Cox of Dynegy; Wesley Allen, representing the Financial Marketers Coalition; Judith Judson, representing the Energy Storage Association; Harry Singh of J. Aron & Co.; and Bob Weishaar of the PJM Industrial Customer Coalition.
Uplift Tab: $5.5 Billion
The report said uplift in PJM, NYISO, ISO-NE, CAISO and MISO totaled $5.5 billion in the 2009-13 period.
While the report noted the charges were a small fraction of energy costs, it said “a failure to make the causes transparent and to price them into the energy and ancillary services markets can undermine the effectiveness of price signals and efficient system utilization and mute investment signals. Volatile uplift charges may also create financial uncertainty for customers, depress liquidity and reduce market efficiency.”
PJM market participants have complained that uplift costs create unnecessary risk because they are unpredictable and not hedgeable.
The persistence of uplift in regions such as the Delmarva Peninsula “may indicate that market pricing is consistently failing to fully capture costs associated with committing and dispatching those resources or the existence of market work-arounds,” the report added. It noted that one PJM generating plant received at least $60 million in uplift annually in four of the five years studied.
The report said added transparency would aid development of solutions to reduce uplift. “For instance, knowing that the vast majority of uplift in a particular import-constrained zone is related to the provision of reactive power could make clear to market participants that the zone is reactive power deficient. This could lead to proposals to address reactive power compensation and potentially send a price signal to enhance reactive power capability. On the other hand, knowing that a majority of uplift in a particular zone is related to local ‘reliability’ could suggest that the model is not incorporating certain constraints or the operators are conservatively committing units to address generic concerns,” the report said.
PJM’s Market Monitor has called on PJM to identify the generators receiving uplift, but PJM officials said they are prevented from doing so by confidentiality rules and would require a FERC order giving them approval. The Monitor says the prohibition against disclosure of market-sensitive information should not apply to uplift. (See PJM Won’t Name Uplift Recipients.)
PJM will create a temporary pricing interface in the ATSI Black River area as a result of a transmission outage. The interface will capture in LMPs operator actions taken to relieve thermal or voltage problems resulting from high loads.
Most of the load buses defining the BLKRIVER closed-circle interface are in the ATSI transmission zone. It will be modeled in the day-ahead market if operators know they will be deploying sub-zonal load management before market deadlines. It will not be modeled in Financial Transmission Rights markets.
The interface will be effective Sept. 1 through Oct. 31, 2014, when the transmission outage is scheduled to be completed.
PJM’s Market Monitor made no new recommendations in its second-quarter report, but that doesn’t mean Joe Bowring didn’t have anything to say.
Instead, the Monitor used his newest State of the Market report to repeat longstanding recommendations and warn stakeholders not to overreact to the winter’s extreme weather, which sent prices skyward and brought the RTO uncomfortably close to having to cut loads.
“Particularly in times of stress on markets and when some flaws in markets are revealed, non-market solutions may appear attractive. Top-down, integrated resource planning approaches are tempting because it is easy to think that experts know exactly the right mix and location of generation resources,” the Monitor wrote.
But the Monitor said the lure of integrated planning, cost-of-service rates and subsidies for favored generation technologies should be resisted because “the market paradigm and the non-market paradigm are mutually exclusive.”
“Once the decision is made that market outcomes must be fundamentally modified, it will be virtually impossible to return to markets.”
The Monitor said criticism of the performance of PJM’s energy and capacity markets is legitimate. But he added, “Before market outcomes are rejected in favor of non-market choices, markets should be permitted to work.”
Capacity Prices Suppressed
The report repeats previous calls to eliminate limited demand response and the 2.5% demand offset from the capacity auction, saying the two combined to reduce revenues in the 2017/18 Base Residual Auction by $3.4 billion, or 31%.
“Premature and uneconomic retirements and the failure to make economic investments in new entry are both the results [of the price suppression]. … The most fundamental required change to the capacity market design is the enforcement of a consistent definition of a capacity resource so that all capacity resources are full substitutes for one another.”
The report said the 22% forced outage rate in early January was evidence that current capacity market rules have insufficient incentives and penalties.
“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. … An increase in capacity market prices must be accompanied by a strengthening of capacity market incentives so that customers can be assured of getting what they pay for.” (See related story, Reaction Muted as PJM Pitches New Capacity Product.)
Below are some statistical highlights from the 442-page report.
Prices, Revenues
The load-weighted average LMP was 84% higher in the first six months of 2014 than the first half of 2013 ($69.92/MWh vs. $37.96/MWh). High fuel prices played a large role in the increase. Had fuel prices been equal to the first six months of 2013, LMPs would have risen only 52% to $57.71/MWh.
All technology types received big increases in net revenues due to the extraordinary prices early in the year: combustion turbine (+730%); combined-cycle (+202%); coal (+338%); nuclear (+96%); wind (+32%); and solar (+14%). All figures assume that these are new plants.
Market Power
Baseload generation had an average Herfindahl-Hirschman Index (HHI) of 1,174 in the first two quarters, making it moderately concentrated under the Federal Energy Regulatory Commission’s Merger Policy Statement.
Intermediate generation averaged 1,719, at the high end of moderately concentrated, but rose as high as 5,693. FERC considers an HHI above 1,800 as highly concentrated (equivalent to between five and six firms with equal market shares).
Peakers averaged a highly-concentrated 6,119 and rose as high as 10,000, similar to patterns seen in 2013.
Nevertheless, market power mitigation ensured that energy, capacity and regulation markets produced competitive results, the Monitor said.
Marginal Units
Coal (47.6%) and gas (41%) units were marginal in all but about 11% of real-time hours in the first six months. Oil set prices for 5.7% of hours while wind units were responsible for about 5%.
In all but 1.4% of wind’s marginal hours, the marginal price was at (23%) or below (76%) $0/MWh.
Dynegy’s purchase of Energy Capital Partners’ New England power plants will immediately make it a major participant in a market where it has been a bit player.
