FERC last week granted Entergy permission to exclude from its system-wide “bandwidth” calculation the above-market portion of the price paid for electricity under two power purchase agreements with generators certified under the Public Utility Regulatory Policies Act and Louisiana’s Renewable Energy Pilot Program (ER14-1640).
Rain CII’s calcining Plant in Sulphur, LA (Source: Rain CII)
The March 17 ruling came despite a protest from the Louisiana Public Service Commission, which contended it was excluded from the settlement agreement.
The decision does not alter the actual value of Entergy Gulf States Louisiana’s PPAs with the Rain CII Carbon calcined petroleum coke facility in Sulphur and the Agrilectric rice hull-fueled power plant in Lake Charles. Rather, the commission is allowing Entergy to internally “re-price” the contracts to accommodate the “bandwidth” process the company uses to ensure that none of its subsidiaries have production costs 11% above or below the company average.
Supporters of Entergy’s position said the company’s re-pricing approach prevents the costs of local and state policy initiatives — such as renewable mandates — from being exported to other jurisdictions. However, the Louisiana PSC called the re-pricing practice “unduly discriminatory” to Entergy Gulf States Louisiana and its customers, which will incur increased costs to cover the entire above-market portion of the contract prices.
The PSC also called the settlement procedure an “abuse” because it only included parties that agreed with Entergy’s original 2014 filing.
FERC disagreed.
“We note that the settlement, and the proposed revision it approves, establishes a policy that is applicable to all similar renewable energy PPAs entered into by any of the participating Entergy operating companies,” FERC said. The commission added that Entergy entered into the PPAs “to meet the requirements of the [Renewable Energy Pilot] Program for the benefit of Entergy Gulf States Louisiana’s customers, rather than for the benefit of the Entergy system as a whole.”
Under the agreement, WPL will acquire five ATC substations valued at $458,820 in exchange for $370,863 in transmission-related equipment, which include a power transformer, storage batteries, 138-kV line frames and foundations, poles and historical air brake switches. The Wisconsin-based companies said the move will better “align ownership of the relevant facilities by function,” providing WPL new distribution facilities while handing ATC more transmission assets, which will be turned over to the operational control of MISO.
Both companies will pay current net book value for all facilities in cash without an acquisition adjustment. ATC said the transaction will have “virtually no effect on transmission rates,” noting that the difference in value between the assets being exchanged is only a “tiny fraction” of the company’s total net utility plant of $3.4 billion. WPL receives nearly all of its transmission services from ATC.
The city of Alexandria, La., is entitled to collect a MISO-related adder of 50 basis points on top of its authorized rate of return on equity without having to make a request to federal regulators, FERC ruled last week (EL15-75).
Alexandria, Louisiana Skyline
The commission said Alexandria’s petition to implement the RTO membership adder was unnecessary because the city was already eligible to do so under MISO’s municipal generic template, a formula municipal transmission owners can use to derive their revenue requirements. FERC last June directed the RTO to include the adder, which became effective immediately (ER15-1067).
The commission also granted Alexandria’s request to defer adder collection until after a decision on an ongoing complaint against MISO transmission owners (EL14-12). In that proceeding, MISO transmission customers argue that the current 12.38% base return on equity earned by owners should be decreased to 9.15%.
FERC has accepted MISO’s request to terminate a generator interconnection agreement (GIA) with EDF Renewable Energy’s 150-MW Merricourt wind project in North Dakota, eliminating the prospect the facility would be granted additional time in the interconnection queue before completing construction.
FERC said MISO’s interconnection policy is clear in denying such extensions unless a project’s development has been hindered by another project in the queue.
“No such circumstances are presented here, and, even if such circumstances were present, Merricourt could not extend its [commercial operation date more than] three years beyond the original COD,” the commission wrote (ER16-471).
Commissioner Cheryl LaFleur was the sole dissenter in the 3-1 ruling, citing worries that the decision could create barriers for other wind projects.
MISO revoked Merricourt’s GIA after the facility failed to meet a Dec. 1 deadline to begin commercial operations, despite a request to extend the term until Sept. 30, 2017. Merricourt maintained the project was eligible for such treatment because it had completed a significant amount of construction and was close to securing a long-term power purchase agreement. Development hit a snag in 2011 when Xcel Energy withdrew its PPA for the project, but Merricourt said it could bring the wind farm online by the end of this year.
FERC’s ruling pivoted on a narrow reading of the text within MISO’s GIA with Merricourt, particularly a provision permitting the developer to extend the in-service date after demonstrating “significant steps to maintain or restore operational readiness.” The commission ultimately agreed with MISO’s interpretation that the language only applies to a facility that has already begun — and then ceased — operating.
FERC added that keeping the wind project active could be unfair to other projects in the queue.
In her dissent, LaFleur focused instead on Merricourt’s progress with the project, which she said was so advanced that it would not cause harm to other project developers.
“In my view, our precedent provides the commission with clear authority to determine whether a COD extension is appropriate in a given case,” LaFleur wrote. “Here, I believe that Merricourt has both demonstrated meaningful progress towards reaching commercial operation in a reasonable timeframe … and effectively rebutted concerns expressed by MISO that the Merricourt project is speculative and potentially harmful to other customers in the queue.”
MISO has said that Merricourt is free to continue work on the project, which has so far cost about $20 million according to the developer. That will require it to re-enter the queue and obtain a new GIA.
VALLEY FORGE, Pa. — The estimated cost for Public Service Electric & Gas’ portion of the Artificial Island stability fix has nearly doubled, from $137 million to $272 million, PJMtold the Transmission Expansion Advisory Committee on Thursday.
“We certainly were surprised when we first saw the numbers,” Steve Herling, PJM vice president of planning, told RTO Insider. “In retrospect, we wish we’d had more foresight. We’re going to have to take a real hard look at what this tells us about our process going forward. We don’t like making an estimate that’s this far off.”
PJM stands by its selection of the project, which involves building a new 230-kV transmission line from the nuclear complex in New Jersey to Delaware.
“Based on what we have seen so far, we still believe we have the right project,” Herling said. “There are elements of the design that we continue to discuss, and we’re looking for opportunities to further optimize it and mitigate costs, but at this point we still believe we have the right project.”
LS Power was chosen to build the line, with PSE&G and Pepco Holdings Inc. assigned to construct the necessary connection facilities. LS Power won the deal in large part because it committed to limiting construction costs to $146 million. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)
“LS Power’s cost cap commitment has not changed, and LS Power continues to focus on successful development of its portion of the Artificial Island project,” company Vice President Sharon Segner said.
Paul McGlynn, PJM general manager of system planning, said the cost allocation of the project would remain the same, with the bulk of the price tag being designated to customers on the Delmarva Peninsula.
After Delaware and Maryland regulators and consumer advocates complained about the seemingly disproportionate cost assignment, FERC suspended PJM’s Tariff changes involving the project’s cost allocation pending additional review (EL15-95).
Herling said the Artificial Island project is unique and there was little to compare it to.
“This is the first time we’ve had to deal with so much work inside of a nuclear station,” he said. “We did our best to add substantial adders … but in some areas they weren’t big enough,” he said. “I don’t know how PJM could have done better with that other than doing more extensive detail design work,” which would be expensive and time-consuming, he said. “We will be talking about that, as far as how to do things differently moving forward.”
The Board of Managers, which approved the Artificial Island project, reviews cost increases but does not need to approve them unless the scope of the project is altered, Herling said.
“We review all significant changes with the board. They will ask us questions. They will ask us to get more information. They may suggest alternatives that we should be looking at. At the end of the day, we will do everything they ask us to do, and hopefully they will be satisfied with the information.” But, Herling said, “If the project continues in the [Regional Transmission Expansion Plan], the board does not have to approve revised costs.”
The board could decide to switch to another project, but that’s not likely, Herling said.
PSE&G’s portion of the project consists of three main elements: installing a static VAR compensator (SVC) at the New Freedom substation; putting in optical ground wire (OPGW) for high-speed relaying; and expanding the Salem substation. Herling noted that the SVC and OPGW work were common to all proposals and that any vendor likely would have run into the same cost issues.
The SVC work, which PJM estimated at $38 million, is expected to cost $43 million more, according to PSE&G, in part because of additional site work including wetland mitigation, storm water management and the relocation of a helicopter pad and several buildings. PSE&G also ran into higher vendor cost estimates, McGlynn said.
Additional site work for the OPGW installation increased PJM’s estimate of $25 million by $14 million.
The Salem expansion, estimated at $74 million, will cost an additional $78 million, in part because of the cost differential for security and access requirements needed to work in a nuclear facility.
“We understood that working in Salem would be more challenging than working at a 500-kV substation in the middle of a cornfield someplace,” McGlynn said. “What we’re trying to look at and consider and get a better understanding of is the difference in cost.”
A number of committee members were incredulous.
“Percentage-wise, this is a big miss as far as what we thought we were looking at,” said Dave Mabry, representing the PJM Industrial Customer Coalition, noting that there are no cost commitments involved in the PSE&G work, all of which is considered an upgrade as opposed to a greenfield project.
“We were at $250 million … now we’re up to $350 million,” Mabry said. “The concern here is, is there another shoe that’s going to drop?”
INDIANAPOLIS — The Clean Power Plan, Order 1000, FERC enforcement and distributed generation were favorite topics at last week’s annual meeting of the Energy Bar Association’s Midwest chapter. Here’s a sampling of what we heard.
“Let’s not talk about how the stay will halt work” on the Clean Power Plan, FERC Commissioner Colette Honorable said. “The industry was moving toward a more renewable future long before the Clean Power Plan came along. Let’s continue our work regardless of the stay. It’s a stay. It’s not a decision on the ultimate merits of the plan.”
Honorable also asked the Energy Bar Association for feedback on whether Order 1000 could be improved. “I know it’s not perfect. … We know that the sticky part is interregional planning. I want Order 1000 to aid in the development of these very important interregional projects and not be a barrier.”
Steve Allen, pipeline safety director at the Indiana Utility Regulatory Commission, commented on the trend of electric utilities acquiring gas businesses to feed their gas turbines. “You can have a good safety culture without having a good pipeline safety management system in place, but you can’t have a good pipeline safety management system without a good safety culture.”
John Tsoukalis, an associate with The Brattle Group, said if FERC prohibits virtual trades at nodes with financial transmission rights in order to stop participants from taking losses on virtuals to increase the value of their FTRs, it would also end legitimate trading and harm the market. “FERC is growing aggressive on how they [prove intent],” he said. “But that’s still a question: How heavily does intent versus economic evidence weigh in FERC’s investigation?”
John Parsons, of the MIT Sloan School of Management, discussed the bidding strategy that landed J.P. Morgan in FERC’s crosshairs for market manipulation in California and Michigan in 2013. “From 10 to 11 p.m., their bid price was negative $30/MWh; from 1 to 2 a.m., their bid price was $999/MWh. What they were trying to do was exploit a seam in the algorithm. [The unit] got paid $999/MWh for the two to three hours it took to ramp down,” he said.
Jim Cater, director of economic and financial policy for the American Public Power Association, questioned the appeal of customer-owned distributed energy resources such as rooftop solar. “There’s a notion that somehow there’s a customer groundswell of this, but I don’t know that many people who are involved with this at home,” he said. “I don’t want to be perceived as a naysayer … but this has got momentum behind it that could benefit from a bit of cost-benefit analysis.”
Donna M. Attanasio, senior advisor for energy law programs at George Washington University Law School, talked about the genesis of the e21 Initiative, which the university launched in 2014 along with the Great Plains Institute, Xcel Energy and others to plot a new regulatory model in Minnesota. “Customers want green power; they want more flexibility. If the utilities aren’t going to provide these, customers are going out and getting it themselves. This is where the e21 Initiative started.”
Stacy Stotts, a partner and member of the environmental and natural resources division at Stinson Leonard Street, commented on the Supreme Court’s stay of the Clean Power Plan. “To say the stay is unprecedented is an understatement. The biggest argument [against the CPP] is that utilities are already regulated under the Clean Air Act. If this argument prevails, the rule is gone, it’s going to be vacated … I think that’s a strong argument. Now, what if the rule is vacated? An important thing to remember is the EPA [still] has to regulate emissions — the Supreme Court told them to in Massachusetts v. EPA.”
Stotts also predicted President Obama’s effort to win Senate approval of a replacement for Justice Antonin Scalia “will be a brutal appointment process.”
Mike Kormos, executive vice president and chief operations officer for PJM, is leaving the RTO on April 15 after 27 years.
Kormos had sought last year to replace retiring CEO Terry Boston, but the post went to Andy Ott, who had long been Kormos’ equal on the organizational chart, with Kormos heading up operations and Ott running the markets.
Formerly executive vice president of operations, Kormos was given his current title and additional responsibility over the RTO’s state and member services in June, as part of a string of organizational changes set off by Ott’s promotion. But with Boston gone and Ott in place, Kormos’ career had hit a ceiling at PJM. (See Boston Retirement Prompts Additional Promotions at PJM.)
“We are grateful for Mike’s countless contributions to PJM,” Ott said in a statement. “His relentless focus on driving operational excellence has helped solidify our reputation as a grid operator. After a very long career with PJM, he has decided that it is time to move on and pursue something new. The entire executive team and I wish him the best in his future.”
In addition to overseeing state and member services, Kormos is responsible for system operations, planning and corporate compliance functions.
The RTO said that Kormos’ position would not be filled and that his responsibilities will be transferred to other members of the executive team. Until then, Ott will assume those functions.
“We have a strong management team that will carry on the day-to-day operations and execution of PJM’s long-term strategy,” Ott said.
Kormos’ top deputy, Mike Bryson, was promoted to vice president of operations, from executive director of system operations, in June.
“Mike Kormos has been a great contributor to PJM, and he’ll be missed,” said Joe Bowring, PJM’s Independent Market Monitor.
A PJM spokeswoman said Kormos has not indicated his future plans. Kormos could not be reached for comment.
FERC last week accepted SPP’s proposed Tariff revisions to identify the U.S.-Canada border as the point-of-sale for potential transactions with Canadian transmission service providers (ER16-704).
The commission’s March 8 order found “establishing a point of demarcation for transactions between SPP and Canadian entities … will clarify the regulatory authorizations required by market participants on both sides of the border for international exports and imports between SPP and Canada.” FERC said the demarcation clarifies that those transactions must be reported to the U.S. Department of Energy and Canada’s National Energy Board.
The order is subject to an SPP compliance filing, due April 7. The RTO said it will modify its Tariff by using the term “source” instead of “resource,” addressing Manitoba Hydro’s assertion that the latter term creates two distinct classes of offers that would restrict transactions by non-resource offers.
SPP gained its interconnection with Canada when Basin Electric Power Cooperative joined the RTO as part of last year’s addition of the Integrated System. (See Integrated System to Join SPP Market Oct. 1.)
SPP told FERC the interconnection allows Canadian utilities to participate in its Integrated Marketplace. It said the Tariff revisions are necessary “to allow Canadian entities to register resources and make them available under SPP’s market rules.”
The RTO completed its first international transaction late last year, importing power from Canadian electric utility SaskPower during a mid-December “emergency situation” in North Dakota. (See SPP, SaskPower Make First International Trade.)
SPP Nears ERCOT’s Wind Penetration Levels
SPP set new records for wind penetration last week, putting it within a whisker of ERCOT for the national record.
The RTO established a new record March 7, when its 9,450 MW of wind energy represented 45.08% of its total load (20,960 MW). That broke the record set the day before, when SPP reported a 44.77% penetration level (9,715 MW of 21,700 MW).
SPP’s wind penetration record is within a tenth of a percentage point of ERCOT’s. The Texas grid operator’s 45.14% record was set Feb. 18, when wind energy produced 13,907 MW.
“We continue to see a lot of wind capacity added,” SPP’s engineering vice president, Lanny Nickell, told stakeholders March 9. He said the footprint’s coal consumption has dropped by about 6% over the last three years, replaced by wind and natural gas.
Wind energy accounted for 13.5% of SPP’s electric production last year, trailing coal (55.1%) and natural gas (21.6%), but surpassing nuclear (8.1%). The RTO had 12,397 MW of installed wind capacity in 2015, accounting for 14.9% of its total. It says it has an additional 33,819 MW under development.
ERCOT has 15,764 MW of installed wind capacity. Wind energy accounted for 18.4% of its electric production in 2015.
CAISO has asked FERC to approve a new Tariff provision that would enable rooftop solar and other small distributed energy resources (DER) to participate in California’s energy and ancillary services markets (ER16-1085).
The rule changes create an “initial framework” to extend market participation to DER smaller than 0.5 MW — the current minimum for selling into the ISO’s wholesale market — by allowing for aggregation at the distribution system level.
CAISO is anticipating participation by distributed generation, energy storage and electric vehicle charging stations, but the framework leaves open the possibility for market entry by other types of resources located on either side of the customer meter. This “broad definition” of eligibility is intended to avoid excluding emerging technologies from participating in aggregation.
“The framework will accommodate various resource types as well as different business models, provided the aggregation is capable of operating as an integrated resource and meets specific technical requirements,” CAISO wrote. Those models could include microgrids interconnected to distribution systems as well as third-party aggregators and utilities operating DER.
The rules would bar some resources from participating in aggregations, including generation rated at 1 MW or greater, demand-side resources bid into the market by curtailment service providers and demand response intended to react to grid emergencies. Generating units between 0.5 MW and 1 MW would need to terminate their participating generator agreements in order to join an aggregation. Also excluded would be resources already participating in a retail net energy metering program.
New Participant Type
The Tariff revisions would introduce three new terms into CAISO’s official market lexicon:
Distributed energy resources: Any resource in the ISO balancing area with a first point of interconnection to a utility distribution company or a metered subsystem.
Distributed energy resource aggregation: A “market resource” comprising one or more DER organized to participate in the wholesale market. Aggregations can contain multiple resource types, but resources will be restricted to participating in a single aggregation.
Distributed energy resource provider: “A new type of market participant,” according to CAISO, DER providers would be owners or operators of an aggregation. They would engage the market through a registered scheduling coordinator, which would submit schedules and bids based on the aggregation’s generation distribution factors.
The rules would permit a DER aggregation to operate at a single pricing node or across multiple nodes. Regardless of the configuration, the resources are required to provide a net response at the nodal level consistent with dispatch instructions, with missteps subject to imbalance charges.
Compensation will be based on nodal LMPs, but CAISO will not directly poll meters in an aggregation, so DER scheduling coordinators must provide the ISO with settlement quality meter data in order to receive payments.
In its filing with FERC, CAISO urges approval of the changes by pointing out that distributed facilities already participate in ISO wholesale markets as both generating and demand-side resources.
“The Tariff revisions proposed in this filing do not change those arrangements,” CAISO wrote. “Instead, the CAISO is extending the same opportunity to support the reliable operation of the transmission system to aggregations of distribution-connected resources, recognizing the significant transformation in the industry and deployment of emerging technologies.”
Connecticut sees itself as an energy technology and policy innovator, but much work remains to help it maintain its leadership position, speakers said at the annual Connecticut Power and Energy Society’s Energy, Environment and Development Conference last week.
Connecticut Gov. Dannel Malloy said he is looking forward to the Clean Power Plan, which he believes will be upheld in the courts. “In Connecticut and New England, what these rules are saying is ‘finally, the rest of the country is going to have to live by the same set of rules that we’ve had to live by,’” he said.
New England has long complained of being at the ‘end of the tailpipe’ from Midwest polluters. Malloy said the CPP will be good for his state’s environment — and its economy. “I think it will level the playing field, at least with respect with our ability to compete with other states [and] with respect to the cost of the eventual product, electric energy.”
David Kooris, director of the City of Bridgeport’s office of planning and economic development, recounted the difficulties the city had winning state and federal regulatory approval for a 1.6-MW anaerobic digester and cogeneration facility built near a wastewater treatment plant. “The regulatory environment isn’t yet ready to accommodate some of the new technologies we’re talking about. That was a tough regulatory process and [state environmental regulators] were working closely with us, knowing it was an objective of theirs. But it was fairly arduous just because of the outdated aspects of the regulations.”
Daniel Sosland, president of the Acadia Center, said technology is creating a historic transition in the electric industry. “The question is how fast will we get there. Will markets drive changes? Will policy keep up?” he asked. “The system that we’ve built and has been reliable is a one-way power flow … but in the system we’re building now, the centerpiece is in your community. It’s in your home, it’s in your place of work.”
Jonathan Milley is director of business development for Vionx Energy, which is developing flow battery technology that proponents say will deliver long-duration energy storage at lower costs than lithium-ion batteries. He talked about storage’s challenges in winning a place in the market. “Storage is trying to find a leg in the three-legged stool in between generation, transmission and distribution, and doesn’t quite know how to fit into the equation.”
Katie Scharf Dykes, the Connecticut Department of Energy and Environmental Protection’s deputy commissioner for energy, spoke of accommodating state public policy goals in deregulated wholesale energy markets. “I hope there’s a peaceful resolution, a productive resolution,” she said. “State public policy goals are not discretionary whims; we have a statutory mandate to cut carbon, and we have an obligation to our ratepayers and our children to address this challenge.”
Paul Hibbard, vice president of The Analysis Group, said resolving cost allocation questions is essential to overcoming the region’s infrastructure challenges. “The real confusing piece is what consumers will pay for which pieces of infrastructure, how much will that cost and what might be the alternatives.”
VALLEY FORGE, Pa. — The estimated cost for Public Service Electric & Gas’ portion of the Artificial Island stability fix has nearly doubled, from $137 million to $272 million, 
CAISO has asked FERC to approve a new Tariff provision that would enable rooftop solar and other small 
