MISO told FERC last week that a group of wind generators alleging special treatment for external generators misunderstands the purpose of the M2 milestone payment in the RTO’s interconnection process (EL15-99).
The generators — EDF Renewable Energy, E.ON Climate & Renewables N.A. and Invenergy — complained to FERC earlier this month that revisions to MISO’s rules would exempt generation outside the RTO’s footprint from providing a cash-at-risk deposit in order to enter the definitive planning phase of the study queue. They argued this was unfair to internal generators, which are required to make the deposit, known as the M2 milestone. (See MISO Beats Challenge on Wind Exports.)
MISO said the complainants are asking that existing external generators seeking network resource interconnection service (NRIS) pay the M2 milestone, which is only required for new generation, regardless of its location. The RTO said the milestone isn’t charged to existing internal generation that only seeks NRIS.
The payment, approved by the commission in 2012, is to discourage speculative projects from entering the queue; withdrawals from the queue result in time-consuming and costly restudies.
“The M2 milestone is a ‘readiness’ milestone, designed to demonstrate that projects are ready to proceed to commercial operation,” MISO said. “External NRIS projects need not demonstrate ‘readiness’ because they must be ‘existing’ generators by definition under the MISO Tariff.”
MISO also disputed the complaint’s claim that not having to paying the M2 milestone gave external generators an unfair competitive advantage. Because it treats existing generation the same regardless of location, MISO said, “under complainants’ theory, internal NRIS-only projects within MISO also would have an unfair advantage, and by extension, also should pay the M2 milestone. Such a position is a collateral attack on the commission-approved Tariff that provides for different payments for NRIS-only projects as just and reasonable.”
‘Unripe Complaint’
MISO also criticized the generators’ decision to file an ‘unripe complaint,’ saying that the language of the revisions was not final. The RTO said such filings circumvent the stakeholder process and that FERC should continue to discourage them.
The generators said that their decision to file was based in part on an e-mail from MISO to Wind on the Wires that said the Business Practice Manual revisions concerning M2 milestone payments was final.
The Planning Advisory Committee in August tabled WoW’s proposal that all external generators seeking NRIS pay a portion of the M2 milestone.
The issue was to be taken up again at the PAC’s Sept. 16 meeting but was struck from the agenda at the request of WoW’s Sean Brady.
Brady said he asked to remove the item from the agenda because of MISO’s email. “Making the BPM language effective immediately indicated that this matter was resolved and a vote on the M2 milestone payment was moot,” he said.
Talen Energy asked FERC on Friday to allow it to sell four generators totaling 1,351 MW in eastern PJM to satisfy divesture conditions the commission set in a December order approving the company’s formation (EC14-112).
In their application to spin off their generation into the new company, PPL and Riverstone Holdings proposed two mitigation packages.
One involved divestiture of six Riverstone plants, and one PPL plant, in New Jersey and Pennsylvania totaling 1,315 MW. The second involved the same six Riverstone plants, plus the 399-MW Crane coal-fired plant in Maryland and two PPL hydro plants in Pennsylvania, for a total of 1,346 MW. (See PPL, Riverstone Accept FERC Mitigation Plan on Talen Spinoff.)
Talen now says it wants to replace the two divestiture packages with a third involving the Crane plant and three former PPL generators in Pennsylvania: the 660-MW Ironwood combined-cycle plant, the 248-MW Holtwood hydro plant and the 44-MW Wallenpaupack hydro generator.
Talen said its request was the result of its inability to negotiate a lease extension for its 158-MW combined-cycle plant in Bayonne, N.J., which was part of both previous divestiture options.
The Bayonne plant provides steam to a tank terminal storage facility, which owns the land beneath the generator. The storage facility is owned by a subsidiary of Macquarie Infrastructure Co., the Australian conglomerate.
Macquarie informed Riverstone last October of its intention not to extend the lease on the generator. (In February, Macquarie agreed to purchase the nearby Bayonne Energy Center, a 512-MW gas-fired generator, from ArcLight Capital Partners.)
Talen said efforts to negotiate an extension of the lease beyond its current expiration in October 2018 “proved futile,” forcing it to retire the plant effective Nov. 1, 2018.
“Accordingly, divesting the Bayonne facility could prove challenging,” Talen said. The proposed “Option 3” divestiture package will provide “the market more flexibility to identify the assets more highly valued by potential purchasers,” it said.
Talen said the revised divestiture plan would have essentially the same reduction in the company’s market power.
The company — which is required to complete its divestiture by June 1, 2016 — asked FERC to rule on its request by Nov. 30.
FERC has agreed to a pre-filing review of Columbia Gas Transmission’s proposed 165-mile natural gas pipeline in West Virginia. Columbia said the formal application of the $2 billion Mountaineer Express Project will be filed in April. If approved, construction will begin in the second half of 2017.
The proposed pipeline is designed to give producers in the Marcellus and Utica shale regions a new gateway to markets in the east. The pre-filing process, which involves a series of public scoping sessions, allows the pipeline operator to modify its design before submitting a formal application.
Senate Democrats Ask Obama to Block Arctic Drilling
A dozen Democratic U.S. Senators last week sent a letter to President Obama asking him to block any more drilling in the Arctic Ocean. The senators had previously opposed Royal Dutch Shell’s drilling program in the Chukchi Sea, which Obama allowed.
“You have stated many times that America must reduce our greenhouse gas emissions and build our capacity for clean, renewable energy,” the letter reads. “Allowing Shell to expand fossil fuel drilling in the Arctic is incompatible with this imperative and with your commitment that the United States will lead the global effort to address climate change.”
The letter was signed by Sens. Sheldon Whitehouse (R.I.), Jeff Merkley (Ore.), Patrick Leahy (Vt.), Ben Cardin (Md.), Bernie Sanders (Vt.), Al Franken (Minn.), Richard Blumenthal (Conn.), Brian Schatz (Hawaii), Martin Heinrich (N.M.), Ed Markey (Mass.), Cory Booker (N.J.) and Gary Peters (Mich.).
NRC Inspecting Failure of Control Valves at Callaway
The Nuclear Regulatory Commission is conducting a special investigation into the failure of three of four steam generator water-flow control valves at Ameren’s Callaway nuclear plant in Fulton, Mo.
The failures were noted in three separate instances: one in August 2014, one in December 2014 and a third at an unspecified date. The 2014 incidents were related to a system modification. The third instance was also related to the same system and has since been corrected.
“The purpose of this special inspection is to better understand the circumstances surrounding the valve failures, determine if the licensee’s extent of condition review was sufficiently comprehensive and review the licensee’s corrective actions to ensure that the causes of the failures have been effectively addressed,” NRC Region IV Administrator Marc Dapas said. Callaway is a 1,190-MW single-unit station that went commercial in 1984.
EPA Hears Criticism of Proposed Methane Emission Rule
Representatives of the oil and gas industry told the Environmental Protection Agency that its proposed rules controlling methane emissions could kill the incentive to produce natural gas.
Industry representatives shared their views at a meeting in Colorado hosted by EPA to hear feedback on the proposed rule, which would cut emissions by 40 to 45% by 2025 compared with 2012 levels. The agency said the rule could add $420 million annually to the cost of energy extraction but would reduce health care costs by up to $550 million a year.
But Kathleen Sgamma of the Western Energy Alliance said the rule would push up the price of natural gas and maybe convince industrial consumers to switch back to dirtier fuels, such as diesel. She and other industry officials noted that while the rules only target the oil and natural gas industries, other industries, such as agriculture, produce significant amounts of methane emissions but would remain unregulated.
PennEast Files FERC Application for Marcellus Shale Gas Pipeline
A group of New Jersey and Pennsylvania utilities filed a formal application with FERC to move forward with the controversial $1 billion PennEast Pipeline project to tap into Marcellus Shale natural gas production, saying the new pipeline would deliver low gas prices, stable electricity rates and a manufacturing renaissance to the region.
The 118-mile pipeline, which is fiercely opposed by environmentalists and adjoining landowners, will deliver 1 billion cubic feet of gas a day from the Marcellus gas region to markets in Pennsylvania and New Jersey. About 72% of the capacity is committed to local distribution companies, including UGI Utilities in Pennsylvania and Public Service Electric & Gas, South Jersey Gas, Elizabethtown Gas and New Jersey Gas in New Jersey. Power plant operators and gas producers have locked up the rest of the capacity.
The Energy Department has agreed to reopen the environmental study of the Northern Pass transmission line, which would import hydroelectric power from Canada.
Developer Eversource Energy made enough changes to the transmission line’s route to warrant preparation of a supplement to the draft Environmental Impact Statement, the department said. Political leaders and environmental groups asked the department to reopen the environmental review of the project in light of the new tower heights, configuration and locations.
The department is also extending the public comment period on the draft EIS to Dec. 31, 2015, and postponing the public hearings to a date to be determined before the end of the new public comment period. Eversource said it does not expect the changes to the schedule will delay the project.
Feds Plan Auction of Offshore Leases for Windmills
Federal officials will seek bids to lease nearly 344,000 acres of ocean floor off of New Jersey on Nov. 9. If fully developed, the area could provide enough power for 1.2 million homes, according to the Interior Department and the Bureau of Ocean Energy Management.
Thirteen companies have qualified to bid on the leases in an area which runs roughly from Long Beach Island to Cape May. Gov. Chris Christie’s administration would have to approve the projects.
By Christopher Hargett, Diana McNally-Barsotti and Joel Yu
The benefits of wholesale electric markets can only be achieved when competition is effective. FERC must not only provide for markets that benefit customers but must also not lose sight of the importance of protecting markets (and customers) against market power abuses. To this end, the focus on customer impacts must remain as FERC considers changes to existing electric market offer caps. Some organized markets have sought to increase offer caps to levels above $1,000/MWh because of the impact seen from high natural gas prices during the extreme weather events in the winter of 2013/14. Such efforts are overly reactionary to one winter season experience and do not indicate that a change in policy and consumer protection is warranted at this time. Moreover, they are predicated on the misguided belief that increasing the offer cap is the only means to properly compensate generators for their performance. Since the advent of organized electric market operation, there has been no evidence that a change to this important offer cap is needed.
Protecting Electric Customers
Bids into wholesale electric markets and associated federal regulations are based on the premise that, absent market power, competitive market pressure should discipline offers to levels at or near suppliers’ marginal costs required to cover short-run operations (including opportunity costs). However, because marginal suppliers may be limited during peak periods, and because the market demand-side load is generally not price responsive, a truly functional competitive market may not be present. As a result, offer caps are necessary to protect customers from excessive prices as generation resources become scarce during high demand periods. Moreover, they take into account the fact that “prices are generally more sensitive to withholding and other anticompetitive conduct under high load conditions,” when more costly supply is required.[1]
Due to the experience of the 2013/2014 winter, organized electric markets are seeking to promote resource availability and performance in ways that add competitive forces to the market’s supply side during peak demand hours. While the organized electric markets have well developed mitigation measures in place, there is no substitute for the $1,000/MWh offer cap as a fail-safe protection to customers. Furthermore, energy market offer caps serve as a valuable incentive for generators to minimize fuel costs, which in turn translates into customer benefits through fair electricity prices. Moreover, the existing cap encourages generators to limit their reliance on spot fuel purchases. This incentive is not only good for economics but also for the reliable operation of the electric system. And, under existing rules, individual generators are able to be compensated for documented increased fuel costs when incurred. Such provisions protect generators as well as consumers, and any change to the offer cap should consider the experience with such requests, as discussed below.
It is also inaccurate to claim that higher short-term price signals will result in better resource performance and help maintain reliability. This hypothesis was proven false in PJM’s experience over the past two winters. In response to high natural gas prices in winter 2013/14, PJM temporarily increased its offer cap to $1,800/MWh for the 2014/15 winter but ultimately had no resource clear above $1,000/MWh. In fact, while prices cleared below $1,000/MWh, generators boosted performance year-over-year. When PJM experienced its all-time winter peak in February 2015, the generator forced outage was 13%, compared to 22% in January 2014. In New York, historical data supports this conclusion as well, as no generator in NYISO has ever demonstrated that it incurred costs above the $1,000/MWh offer cap, including the 2013/14 winter when natural gas prices spiked to unprecedented levels.
Regional Coordination
FERC should not act on a generic basis to modify energy market offer caps across organized markets, nor should it allow differences in offer caps between regions. Contrary to FERC’s goal, any difference in offer caps in neighboring regions would create unnecessary seams issues and could result in inefficient bidding behavior between regions. That’s because suppliers could concentrate their offers into the market with the higher offer cap, forcing operators in the lower offer cap region to call on resources out-of-market to meet their system reliability needs. This would unnecessarily increase costs to consumers in both regions. Such bidding incentives are an unjust application of market power and should be avoided. True price flexibility and differentiation between markets are, and should continue to be, a reflection of infrastructure constraints.
The Right Approach
Price signals are not the only tool available to compensate suppliers according to their cost of operation.[2] Out-of-market payments are the appropriately tailored solution when considering the precarious alternative. Taking this approach ensures that generators are compensated for their performance and for meeting customer needs in extreme conditions, without creating potential market vulnerabilities at all other times to the detriment of electric customers. Out-of-market payments address these rare costs in a fair manner for generators and customers and should be transparent for all market participants. Trends should be monitored, and any changes, if considered in the future, should be based on information about such payments.
[2] PJM recently received FERC approval for its Capacity Performance program, whereby units that perform under high demand conditions are rewarded. In New York, NYISO is undertaking several initiatives to bolster performance while ensuring compensation including clarifying market mitigation measures and fuel availability reporting.
Christopher Hargett, Diana McNally-Barsotti and Joel Yu are senior policy advisors at Con Edison. Subsidiaries Con Edison Company of New York and Orange and Rockland Utilities are transmission owners within NYISO. A subsidiary of Orange and Rockland Utilities, Rockland Electric, is a transmission owner within PJM.
(Editor’s Note: This column marks the beginning of an occasional RTO Insider feature, Stakeholder Soapbox. If you’d like to contribute your own op-ed article, contact Rich.Heidorn@RTOInsider.com.)
IPPNY President Gavin Donohue said generators are willing to work with New York regulators regarding the state’s capacity market but said it’s unclear what changes are being sought. “What problem are we trying to solve?” he asked. “We’ve had stresses on the system during the winter [and] during the summer the last few years and quite frankly the system has worked very well.”
IPPNY Chairman John Reese, senior vice president of US Power Generation, called on state regulators to demonstrate “courage” by pushing for an increase in the cost of new entry. “Nobody believes you can actually build or enter the New York market for the current cost of new entry price,” he said. “Upstate New York capacity prices are lower than PJM, are lower than New England. Those are not survivable.”
Kenneth Daly, CEO of National Grid New York, speaks as James Gallagher, executive director of the New York State Smart Grid Consortium (left), and UBS Securities analyst Michael Weinstein (right) listen. Daly said the next five years of the state’s Reforming the Energy Vision initiative will be transitional, as state regulators evaluate demonstration projects and determine which worked and which did not. “Ten years from now is when we’ll start to see game changers. Battery storage is clearly the one biggest change that our industry will face. And if we go through another investment cycle these next five years of modernizing our grids we’ll then have far greater capability in that second five-year period to integrate renewables, to give customers choice, to use more local demand response.”
Richard Dewey, executive vice president of NYISO (left), and John Shelk, president of the Electric Power Supply Association (right), said EPA’s final Clean Power Plan addressed problems with the draft rule. Dewey said the preliminary rule “would have left us with about one to three days of oil burn in New York state – which is about 100 less than we typically need [for] reliability.” Shelk said the final rule fixed an “artificial” advantage for new gas plants. But he said it remains unclear how regions outside the Regional Greenhouse Gas Initiative will incorporate carbon costs in economic dispatch. “Clearly we’re not going to have — certainly not on day one — a price on carbon in the rest of the states,” he said.
SPP will welcome the Integrated System and its three primary entities as full members Thursday, extending its footprint into Big Sky Country.
The IS — comprised of Western Area Power Administration-Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District — expands SPP’s footprint to 14 states, adding the Dakotas and parts of Iowa, Minnesota, Montana and Wyoming.
It will add more than 5,000 MW of peak demand and 9,500 miles of transmission infrastructure to SPP’s responsibilities, while increasing its territory by 55% to 575,000 square miles.
“It’s a significant change for SPP, considering the amount of area we’re responsible for and the parties we’re responsible for as members,” Executive Vice President Carl Monroe, SPP’s chief operating officer, told RTO Insider. “We’re extending our footprint and ensuring SPP’s members will get the benefits of our services.”
While SPP expands with the IS, indications are it will not gain another potential member with Lubbock Power & Light’s announcement last week that it will join ERCOT in 2019.
Reliability Coordination Began June 1
SPP has been providing reliability coordination for the IS since June 1, monitoring power flow and managing congestion while WAPA, Basin Electric and Heartland dispatched their generating resources. The three entities will transfer functional control of their facilities to SPP at midnight Wednesday night and become active participants in the Integrated Marketplace, forming the new Upper Missouri transmission zone.
Other entities will become full SPP members Thursday, including the East River Electric Power Cooperative, Northwest Iowa Power Cooperative and Corn Belt Power Cooperative. It will be SPP’s first major membership additions since 2009, when Nebraska’s major utilities joined the RTO, and boosts its membership to 92.
“We’re really looking forward to Oct. 1,” Monroe said. “We have very good relationships with those parties, and some are already participating in SPP’s working groups.”
SPP prides itself on being a stakeholder-driven organization and its governance model was a major reason the IS joined. Heartland CEO Russell Olson cited the RTO’s “collaborative process” in a statement announcing the move last year.
“They felt they would have a voice,” Monroe said, “and that made a difference in their decisions.”
Joining SPP gives IS members access to the RTO’s markets. Several current members have already credited market savings with allowing them to reduce the size of rate increases or providing additional pricing efficiencies through a broader pool of resources.
“I would guess that would be able to happen again from expanded footprint,” Monroe said. “Savings in the energy market will reduce the cost of wholesale energy. Depending on how each entity handles its customers, it could be a reduction in costs.”
Monroe said SPP’s increased membership also will reduce RTO service fees for existing members. “Everyone will be paying less as a ratio than they would have paid before,” he said.
WAPA, Basin Electric and Heartland began discussing joining an RTO four years ago to increase their options for buying and selling power. All three conducted public hearings and assessments before determining last year that SPP was the best fit. FERC approved the move in November.
“We felt that SPP was a solid philosophical match for our cooperative,” said Paul Sukut, Basin Electric’s CEO and general manager.
WAPA will become the first federal power marketing administration to join an RTO. WAPA spokesperson Lisa Meiman said joining SPP “alleviates the marketing restraints” the agency was facing in delivering firm power to its customers.
Because the Energy Policy Act of 2005 placed conditions on power marketing administrations joining RTOs, SPP did have to “accommodate” WAPA’s “unique needs,” Meiman said. SPP modified its Tariff to exempt WAPA from regional cost-sharing charges. WAPA also is exempt from congestion and marginal loss charges when it is marketing and delivering federal hydropower to its federal load, she said. FERC issued an order Monday approving SPP Tariff changes accommodating WAPA (ER15-2350).
WAPA will merge its Eastern Interconnection balancing authority into SPP’s balancing authority, and its Eastern and Western Interconnection transmission facilities will be incorporated into the new Upper Missouri Zone. Meiman said WAPA will remain a transmission operator and develop transmission rates, revenue requirements and other necessary rates for use in SPP’s Tariff.
WAPA’s Western Interconnection BA will not become a part of SPP’s BA, nor will UGP’s Western Interconnection generation and load become part of the Integrated Marketplace.
Lubbock Sees Savings in ERCOT
Excitement over the addition of the IS was tempered last week when Lubbock Power & Light, which receives its energy through SPP member Xcel Energy, said it will join ERCOT to reduce its energy and capacity costs. (EDITOR’S NOTE: An earlier version of this story incorrectly stated that Lubbock Power & Light was an SPP member.)
The LP&L Electric Utility Board met with the Lubbock City Council on Sept. 24 to outline its transition to ERCOT, which manages 85% of the Texas grid. LP&L is the third-largest municipally owned electric company in the state, after San Antonio and Austin.
“That’s their decision,” Monroe said. “We’re a voluntary organization. If that’s what they intend to do, they make those choices that are best for their organization.”
LP&L says significant transmission infrastructure will be needed to interconnect with ERCOT, and that approval, certification and construction will likely take four years. The process began with a feasibility study, which was approved by the Public Utility Commission of Texas last week.
The utility says taking advantage of smaller, cheaper contracts in the ERCOT market will save it $20 million annually over what it currently spends in a long-term wholesale contract with Xcel Energy. LP&L’s three old, small power plants are seldom committed.
Lubbock also will be freed of about $40 million in annual capacity fees in ERCOT’s energy-only market.
LP&L also said it will benefit from Texas’ diversified energy portfolio and a simplified regulatory environment.
Monroe said SPP hasn’t had any conversations with LP&L or Xcel or looked at the implementation plans. “I’m not sure what [the announcement] means,” he said.
In a press release, Xcel expressed disappointment and said the city’s proposal will increase costs for customers in both ERCOT and the areas it serves in SPP. Noting the “significant investments” it has made in the area’s high-voltage network, Xcel said “Lubbock’s portion of the annual cost of these investments will be added to the costs Xcel Energy customers in Texas and New Mexico already pay.”
Xcel also said its long-term power supply agreement for a portion of Lubbock’s power needs through 2044 could be “impacted” by the utility’s move to ERCOT. According to LP&L, it will honor the contract by purchasing 170 MW from Xcel after June 1, 2019, which means it will remain interconnected with SPP.
By joining ERCOT, the city says it would also escape FERC regulation. As a Texas-only grid operator, ERCOT is regulated by the PUCT and the state legislature; FERC governs SPP and other interstate providers.
The PUCT and ERCOT would both have to approve LP&L’s move.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be at the PJM Conference and Training Center in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report. (Note: The meetings were delayed by a week because of the pope’s visit to Philadelphia and relocated to the CTC because facilities were not available in Wilmington on the new date.)
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
Manual 40: Certification and Training Requirements. Makes miscellaneous edits; clarifies concepts, roles and responsibilities related to PJM’s systematic approach to training; updates the process for member training and PJM certification and reflects changes in terminology of operator titles.
Manual M10: Pre-Scheduling Operations. Adds procedures for maintenance outages under Capacity Performance rules: the requirement for PJM members to provide estimated “early return time” for planned outages; ensures that PJM will coordinate rescheduling if it withdraws or withholds approval of a planned outage; references PJM’s authority to withhold or withdraw approval of maintenance outages with at least 72 hours’ notice; adds requirement that maintenance outages be submitted at least three days prior to the operating day of their commencement.
Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. The proposal, hammered out by Direct Energy, Old Dominion Electric Cooperative, the Independent Market Monitor and the PJM Power Providers Group (P3), would cap cost-based offers at $2,000/MWh and allow them to set LMPs, with market-based offers allowed to equal cost-based. Generators with approved fuel cost policies claiming costs above $2,000/MWh would be compensated through make-whole payments. (See related story, Consensus Near on Energy Market Offer Cap?)
Members Committee
CONSENT AGENDA (1:20-1:25)
B. The committee will be asked to endorse Reliability Assurance Agreement revisions regarding external capacity rights. The rule change allows load-serving entities to meet their internal capacity requirements using historic resources under certain conditions: The percentage internal resource requirement is enforced only if the locational deliverability area has been separately modeled due to certain triggers; a fixed resource requirement entity is permitted to terminate its FRR alternative election prior to meeting the minimum five-year commitment period requirement under certain conditions; and first-time elections of the FRR alternative are due four months prior to a Base Residual Auction instead of the current two-month deadline. (See IMEA Reaps Limited Relief from Capacity Rule Change.)
C. New Tariff language reflects the switch from eMkt to Markets Gateway.
ENDORSEMENT (1:25-2:25)
Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. (See MRC agenda item 3, above.)
SARATOGA SPRINGS, N.Y. — New York Power Authority CEO Gil Quiniones says the state-run company will be the “most innovative and advanced utility in the U.S. in a very short period” due to massive investments and its commitment to facilitate the remaking of the industry in the state.
Quiniones
Addressing the fall conference of the Independent Power Producers of New York, Quiniones said NYPA expects to spend $3 billion to $4 billion on infrastructure over the next decade, with nearly half of that total — $1.5 billion — in smart grid generation and transmission assets.
New York has embarked on the Reforming the Energy Vision initiative to transition to cleaner and more distributed generation. NYPA’s five-year strategic plan was written in the context of REV, he said.
That means a revamping of operating procedures and technologies that can accommodate distributed resources. “As we move into this REV world, we have to be sure that all this generation and transmission infrastructure works in synchronicity with the advent of distributed resources,” Quiniones said. “… Our grid has to be connected and smart and optimized and the only way to do that is to digitize it and use big-data analytics.”
NYPA has 16 power plants and 1,400 circuit miles of transmission, including one-third of the state’s high voltage system. It serves 51 small municipal and rural cooperatives.
One project now underway is the retrofit of the Massena substation, which Quiniones said will result in “the most advanced substation of its size in this country. It will be microprocessor-based, fiber optic-based; it will provide unparalleled situational awareness and operational flexibility.”
Last year, NYPA built a 15-MW microgrid on Rikers Island in New York City, which captures waste heat from the facility and runs parallel and synchronous to the utility system. It can island in the event of another city-wide power interruption, such as during Superstorm Sandy. This is intended to be the first of several microgrids NYPA will build.
NYPA is acting as a facilitator with vendors SolarCity and SunEdison to install solar panels at the 698 school districts in the state. “I predict there will be a very fast ramp up of solar in our public schools,” Quiniones said.
In October, six drones from different vendors will be tested to monitor the condition of power lines. The authority also is beginning to monitor power line conditions and operations with a robotic device from Hydro-Quebec.
Much of the innovation is taking place in the North Country, home to most of the state’s wind farms, whose variability stresses the system.
Other initiatives include:
Installing dynamic line rating technology sensors and intelligence so the system can know exactly how much power is being carried through its lines. This aids efficiency by acting as a “fast switch” as it can transfer as much as 300 MW from one line to another in milliseconds to prevent system overload;
Condition-based monitoring that would base equipment replacement on the condition of the asset rather than on manufacturers’ recommendations;
Transformer-testing software to prevent catastrophic events.
The authors of four competing proposals to change the $1,000/MWh energy market offer cap have agreed to put forward one plan for consideration by the PJM Markets and Reliability Committee on Thursday — the last chance stakeholders will have to come to consensus before the Board of Managers takes the issue into its own hands.
The proposal outlined during a special MRC meeting last week would cap cost-based offers at $2,000/MWh and allow them to set LMPs, with market-based offers allowed to equal cost-based. Generators with approved fuel-cost policies claiming costs above $2,000/MWh would be compensated through make-whole payments.
There would be no change to the treatment of the 10% adder, shortage penalty factors and start-up or no-load compensation. Cost-based offers would be considered to include the 10% adder.
The framework was hammered out during a conference call last week attended by Direct Energy, Old Dominion Electric Cooperative, PJM Power Providers Group (P3), the Independent Market Monitor — jokingly dubbed “the four horsemen”— and PJM staff.
“I think it’s fair to say that none of the four proposers who participated in the call felt it was their home run,” said committee secretary Dave Anders. “But it was something they looked at as a bridge that, should the stakeholders come to consensus on it or something close to it, it could work for this winter and until FERC” takes action.
Stakeholders already had been rushing to reach consensus after being told in July at the Liaison Committee meeting that the Board of Managers planned to take up the issue in time for winter.
Then, on Sept. 17, FERC announced its intention to take action on offer caps and other price formation issues. The commission made the statement as it issued a proposed rule requiring RTOs and ISOs to align their settlement and dispatch intervals (RM15-24). It gave no timeline for future action. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)
PJM Approves
PJM’s Adrien Ford said the new framework “is something PJM staff can fully support” to the board.
Absent consensus, she said, staff is prepared to recommend a Tariff change similar to the waiver it filed last year, which allowed prices to rise as high as $1,800/MWh. PJM made it through the winter without having to invoke it.
Staff would recommend, however, that the increased cap remain beyond the winter and would clarify in its transmittal note that any FERC action would supersede the new language, Ford said. “We view it as an interim solution for a winter or two,” she said.
PJM staff hasn’t finalized exactly what it would recommend if consensus can’t be reached, she said. One outstanding issue is whether to eliminate the cap altogether. Any solution supported by PJM would allow generators full cost recovery, she said.
Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during extreme conditions such as the 2014 polar vortex.
On Thursday, ODEC, Direct Energy and the Market Monitor said they would withdraw their proposals to support the new framework. David “Scarp” Scarpignato of Calpine, which is a member of P3, said he hadn’t had time to canvass the group to guarantee they would do the same, but he said initial feedback from the P3 members he reached during a break in the meeting pointed in that direction. (See PJM Stakeholders Weigh 4 Options on Offer Cap; No Agreement in Sight.)
“We see there are some areas we’re not going to come to agreement in the time we have to do so,” said Steve Lieberman of ODEC. “But we’re probably not as far apart as we may have thought. Is it perfect? Absolutely not. We shouldn’t let that get in the way of an incremental improvement.
“It’s hard to argue that this is not an improvement. It does allow generators to recover their costs. It does offer load the security blanket of a cap, albeit higher than we otherwise would wish to support.”
Susan Bruce, representing the PJM Industrial Customer Coalition, agreed.
While noting that she had not reviewed the proposal with her clients, Bruce called it “a good-faith effort at compromise.”
She said she was pleased that market-based bids above $1,000/MWh must be below the cost-capped bids and that a hard cap will remain at $2,000/MWh.
“It addresses — maybe not ideally, but practically — many of the concerns that have been raised. While there are areas of this that would give customers pause, I think it’s hard to view this as anything but a good workable framework around consensus,” she said.
“It addresses my clients’ particular concerns about our aggregate market power. … The 10% adder is problematic, but if we’re looking for consensus, it will necessarily involve compromise.”
Exelon, Maryland Balk
Not everyone was on board, however.
“It falls woefully short of correct market principles that PJM should be endorsing and has endorsed in the past,” said Exelon’s Jason Barker. Payments to individual units, recovered in uplift, fail to send clear market signals, he said.
Walter Hall of the Maryland Public Service Commission said that the state would be unlikely to support an offer cap as high as $2,000.
“We have not been persuaded that there is a need at this time [for] a raising of the offer cap; however, we do agree that generator cost recoveries are important and would be willing to see some mechanism added to the PJM Tariff that would provide that, but without setting [LMPs],” he said. “We’re willing to discuss some alternative to that, some higher level of offer cap, but unlikely to be willing to go as far as $2,000.”
Hall also asked for more information regarding the generators most likely to be on the margin and setting the highest costs.
“We would have some concern that perhaps there are very inefficient units being maintained here that would be providing the last megawatt of electricity,” he said.
Three new transmission developers affiliated with established utilities have entered the race for competitive transmission projects in the Midwest.
FERC this month conditionally accepted formula rate templates and related protocols for two new developers in SPP and one in MISO.
The commission acted on filings by ATX Southwest (ER15-1809), an affiliate of Ameren; Kanstar Transmission (ER15-2237), an affiliate of Westar Energy; and Midwest Power Transmission Arkansas (ER15-2236), whose parent is a joint venture of Westar and Berkshire Hathaway Energy.
Midwest Power set its sights on MISO, which expects to issue its first competitive solicitation under FERC Order 1000 as part of its 2015 Transmission Expansion Plan.
ATX and Kanstar intend to compete in SPP, which issued a request for proposals May 5 for its first competitive upgrade, the 21-mile North Liberal-Walkemeyer 115-kV project in Kansas. (See Walkemeyer Transmission Project Wins SPP OK.)
The commission approved the companies’ proposed base returns on equity (ROE) for filing, setting them for hearings and settlement procedures.
Midwest Power was granted use of MISO’s base ROE, currently 12.38%, subject to the outcome of complaints challenging the rate (EL14-12 and EL15-45).
ATX’s request for a base ROE of 10.9% and Kanstar’s requested 10.5% base were accepted for filing and set for hearing and settlement judge procedures.
All three companies also were awarded 50-basis-point adders for participation in an RTO, subject to the total ROE being within the “zone of reasonableness” established in the hearing and settlement procedures.
Also approved were the companies’ hypothetical capital structures, 60% equity and 40% debt for Kanstar and Midwest, and 56-44 for ATX.
FERC denied ATX’s request to recover costs related to transmission facilities abandoned for reasons beyond the entity’s control and its request to include 100% of construction work in progress (CWIP) in its rate base during development and construction. It also denied ATX’s request to include 50% of CWIP in its rate base for all transmission projects it is awarded through SPP’s Order 1000 solicitation process.
FERC also denied Kanstar’s request to recover 100% of costs associated with its proposed Walkemeyer project, should the company be selected to develop the project and it is later discontinued.
The commission announced its orders on Kanstar and Midwest Power at Thursday’s open meeting.
Unfinished Business
In a related order, the commission on Wednesday dismissed as moot a 2013 petition by the trade group WIRES seeking a generic “statement of policy” on regulated rates of return for transmission investments (RM13-18).
WIRES, which represents transmission owners, made the petition in an attempt to counter a dozen complaints challenging as unjust and unreasonable the FERC-approved ROEs for transmission owners around the country.
The commission said it had addressed the issue in Opinion 531, its June 2014 ruling adopting a two-step discounted cash flow method for setting ROEs (EL11-66-001). (See FERC Splits over ROE.)
The group issued a press release expressing disappointment in the commission’s rejection of the petition.
“The downward pressure on ROEs has increased since Opinion No. 531, as have the uncertainties of ongoing litigation,” said WIRES Counsel Jim Hoecker, a former FERC chair. “If other investments become more attractive to investors than transmission, the long-term impacts on the [Environmental Protection Agency’s Clean Power Plan], renewable energy development and the commission’s pro-market objectives could be significant.”
With the number of would-be transmission developers continuing to grow, however, there’s little evidence that the sector is having trouble attracting investment.
