ST. PAUL, Minn. — MISO, SPP and intervenors in the dispute over MISO’s use of SPP transmission to deliver power between its northern and southern regions have begun circulating drafts of a settlement amid optimism that it will be filed with FERC in October (ER14-1174).
Discussions on how costs paid to SPP will be allocated within MISO will begin in September “on a separate track,” Eric Stephens, deputy general counsel, told members at the MISO Informational Forum last week. Stephens said confidentiality rules on the settlement talks prevented him from discussing specifics of the deal.
But Market Monitor David Patton told the Markets Committee of the Board of Directors later that the settlement will allow MISO to eliminate use of its $9.57/MWh “hurdle rate” in determining whether to allow more than 1,000 MW of power flows between its two regions.
“We need to make sure that’s the case, but I think the team at MISO did a good job of moving the settlement in a direction that allows us to do that,” Patton said.
MidAmerican Energy’s Dehn Stevens told the Board of Directors meeting later that the Transmission Owner sector is “very comfortable with where [the settlement is] at.”
Organization of MISO States President Libby Jacobs told the board that her group is “very optimistic that there’s resolution on the horizon.”
“OMS would encourage that to be rapidly finished so that everyone’s focus can be on other issues,” she said.
In spring 2014, MISO began limiting flows between its northern and southern regions after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW contract path.
While seeking to resolve the dispute with SPP, MISO implemented a $9.57/MWh hurdle rate — an adder to the LMPs of the importing sub-region — to establish market signals indicating when the savings from avoided redispatch costs exceed SPP’s additional transmission charges.
Patton: Fear of FTR Gaming over WAPA Integration Hasn’t Materialized
Patton told the Markets Committee that his staff has seen little evidence to confirm fears that SPP’s integration of the Western Area Power Administration (WAPA) could give market participants an opportunity to game the market by buying financial transmission rights from SPP “whose value predictably would change significantly” following the integration.
“We didn’t see a lot of participants engage in strategic FTR purchases the way we had thought they would,” Patton said.
He said his staff is continuing to review how SPP’s dispatch including WAPA affects MISO’s constraints in the FTR market and market-to-market process.
“We don’t have significant concerns, but it is a significant change because WAPA stretches from the Dakotas down to the southern end of SPP. It’s a huge change in their configuration. You can think of it as similar to our integration of MISO South.”
“So, no red flags, just continued vigilance?” asked Director Michael Curran.
The New York Public Service Commission on Friday requested NYISO to perform reliability studies in western New York after NRG Energy announced it was retiring one coal plant and suspending plans to convert another to natural gas.
NRG said Aug. 25 it would retire the 380-MW Huntley Generating Units in Tonawanda, north of Buffalo, and halt plans to convert the 435-MW Dunkirk Station, southwest of Buffalo, to natural gas.
The PSC request capped a week in which NRG’s announcement and protests over ratepayer subsidies to a third plant roiled the upstate New York power market, putting more than 1,100 MW of generating capacity in question.
NRG said it plans to mothball Dunkirk on Dec. 31, when a current reliability support services agreement expires, and retire Huntley on March 1, 2016.
NRG won approval from the PSC more than a year ago to convert the Dunkirk plant to natural gas at above-market rates. Dunkirk would have received out-of-market payments of $20.4 million per year from National Grid and a one-time $15 million subsidy from New York state.
Entergy, owner of the 838-MW James A. FitzPatrick nuclear plant in western New York, sued the PSC in federal court in February, claiming the subsidies interfered with FERC’s jurisdiction over the wholesale power market. (See FERC: Hearing or Settlement on Dunkirk RSSA Charges.)
NRG said the lawsuit made the planned conversion unworkable. “Currently, NRG expects that the Entergy lawsuit will go to trial and litigation on this case could take years to resolve,” spokesman David Gaier said. “Unfortunately, the Entergy lawsuit has created a tremendous amount of uncertainty for NRG in moving forward with the Dunkirk project, and at this point the project remains on hold.”
NRG blamed low natural gas prices, low energy prices and low capacity prices for the Huntley closure. “Thus, because the facility is not currently economic and is not expected to be economic, NRG intends to retire the units. Should circumstances change, NRG will notify all parties to this notice,” it said.
The PSC requested NYISO consider three scenarios: both Huntley and Dunkirk close; Dunkirk closes but Huntley remains open; and Huntley closes but three Dunkirk generators (Units 2, 3 and 4) remain in service after March 1. The ISO was also asked to describe transmission upgrades or alternative resources that could address any reliability problems resulting from the closures, including cost estimates and implementation schedules.
The PSC also requested that distribution company National Grid reassess its transmission needs. The company had assumed Dunkirk would continue operating, so it may need to plan transmission alternatives if the closure is permanent.
NRG’s announcements could force NYISO to reconsider the conclusions of a recent study that said previous concerns about system reliability were mitigated for 2016 by the restoration of plants such as Dunkirk. (See NYISO: Reliability Concerns Raised Last Year Resolved.)
If the PSC determines reliability is again an issue, it could order National Grid to negotiate an RSSA with NRG to keep the plants running.
Capacity Performance resources cleared at $134/MW-day in the transition auction for the 2016/17 delivery year, PJM announced Monday.
PJM held the auction Aug. 26-27 to obtain CP resources for 60% of the updated reliability requirement for 2016/17, procuring its target of 95,097 MW.
The clearing price was well below the price cap of $165.27 — results that Stu Bresler, senior vice president for markets, said “demonstrated the competitiveness of the auction.”
But speaking at a conference in Boston, Jim Wilson, a consultant for consumer advocates, said PJM paid far more than it needed to, asserting it could have procured the CP resources for only an additional $30/MW-day rather than the “windfall” that resulted from the auction.
Market Monitor Joseph Bowring, also appearing at the conference, declined to comment on the results, saying he would be issuing a comprehensive report in a few weeks.
Of the capacity that cleared, 90,851 MW represented resources committed in previous auctions that now will be converted to the new product at a higher price. The remaining 4,246 MW did not have a prior commitment, or surpassed the level of a previous commitment.
Total capacity offered into the auction was 117,753 MW.
“There wasn’t anything that surprised me that much,” Bresler said in a press conference after the results were announced late Monday. “The clearing price was just about at the point where we expected it to be.
“I thought the level of demand response and energy efficiency was not surprising, so really I think in just about every way it was consistent with what we expected.”
The auction, part of a five-year transition period leading up to a single capacity product type for the 2020/21 delivery year, had been delayed in order to allow DR and energy efficiency resources to participate, per a FERC order. A second incremental auction, for the 2017/18 delivery year, is set for Thursday and Friday, with results expected to be posted on Sept. 9.
The Base Residual Auction for the delivery year — held in 2013, before the introduction of the tougher CP requirements — cleared at prices ranging from $59 to $119/MW-day in most of PJM, with the PSEG locational deliverability area at $219. (See Capacity Auction: New Generation, Imports Up, Prices, DR Down.)
Bresler said 619 MW of DR cleared the auction, of which 227 MW represented a new commitment. All 949 MW of energy efficiency offered cleared, including 423 MW of new resources.
Under the rules of the transition auctions, participation is optional, and market participants may offer all or part of resources that were committed under the Base Residual Auctions for those years as Capacity Performance resources.
The parameters of the transition auctions differ in three aspects, Bresler said: There were no locational constraints modeled; the target was 60%, not 100%, of the reliability requirement; and a price cap was implemented that was calculated to be 50% of the net cost of new entry.
The incremental cost of the transition auction was $2.3 billion, slightly below the estimate of $2.5 billion to $3.6 billion PJM and the Market Monitor had predicted, Bresler said.
Bresler sought to counter news reports that the new Capacity Performance auctions would greatly increase consumers’ power bills, noting that CP costs make up about 15% to 20% of energy bills, and that energy payments are expected to be lower because the new construct will result in better resource availability during times of extreme weather and grid stress.
Breaking down cleared megawatts of capacity by generation source, coal cleared 32,622.3; gas 29,629.4; and nuclear 26,099.8.
The RTO’s first Base Residual Auction under its new Capacity Performance rules, the results of which were released Aug. 21, saw prices rise 37% to $164.77/MW-day in most of the RTO, while the ComEd zone broke out at $215 and Eastern MAAC hit $225.42.
The construct allows capacity resources to receive higher prices in exchange for taking on more responsibilities and stiffer penalties for non-performance.
Capacity Performance resources, which represented more than 80% of capacity acquired in the BRA, were priced at a $15/MW-day premium to base capacity in most of the RTO. In the winter-peaking PPL LDA, the premium was $90. (See PJM Capacity Prices Up 37% to $165 /MW-day.)
FERC on Tuesday rejected complaints from NextEra Energy and Direct Energy seeking to change the way PJM conducts its incremental capacity auctions to transition to its new Capacity Performance product (EL15-88).
The commission found that the companies failed to show how PJM’s clearing methodology for the auctions was inconsistent with the RTO’s Tariff and that their proposed alternative plan “relies on a complicated and untested algorithm to clear the capacity markets.”
“Implementing an untested alternative proposal would require other changes to either PJM’s market design or [Tariff] in order to be justly and reasonably implemented, and therefore complainants’ alternative clearing methodology cannot be said to conform to the [Tariff] itself,” FERC said in its order.
The transition auctions are being held to procure Capacity Performance resources for delivery years 2016/17 and 2017/18. PJM ran the first Base Residual Auction, for 2018/19, under the new product earlier this month. (See PJM Capacity Prices Up 37% to $165/MW-day.) It allows capacity resources to receive higher prices in exchange for taking on more responsibilities and stiffer penalties for non-performance.
Under the rules of the transition auctions, participation is optional, and market participants may offer all or part of resources that were committed under the BRAs for those years as Capacity Performance resources. If cleared, the Capacity Performance commitment would replace the old one and participants would receive the new, higher price.
Incremental Costs
NextEra and Direct Energy argued that this methodology would result in increased costs, in violation of both PJM’s Tariff and FERC’s order authorizing Capacity Performance, which the companies said directed the RTO to procure capacity resources using the “least-cost solution.”
The companies said that in order to do this, PJM needs to take into account the results of the BRAs for 2016/17 and 2017/18 when selecting offers. Rather than simply selecting the lowest price, they suggested that the RTO base its selection of resources on the lowest incremental cost — the difference between the new Capacity Performance price and the price under the original BRA. (See table below.)
Direct Energy and NextEra Energy proposed an alternative clearing methodology for the transition auctions in which PJM would select resources based on the lowest incremental cost (the Capacity Performance price minus the original BRA price), and not simply on the lowest new price.
FERC disagreed.
The RTO’s Tariff does not “require PJM to minimize costs by taking into account existing capacity revenues for the delivery year or other savings in determining the lowest price at which to clear an auction for Capacity Performance products,” the commission said.
FERC also insisted that ordering PJM to revise its methodology now would delay the transition auctions and reduce the amount of time that generators have to install upgrades needed to meet Capacity Performance’s more stringent requirements.
The commission issued its order the day before the first transition auction began. Results for this auction were released on Monday. (See related story, PJM 2016/17 Transition Auction Clears at $134/MW-day.) The second auction will be Sept. 3-4, with results posted on Sept. 9.
Bay Dissents — Again
In a dissent, FERC Chairman Norman Bay agreed with the companies. He said that the transition auctions allow the RTO to avoid making payments it would otherwise make and, in turn, save consumers money.
Bay illustrated NextEra and Direct Energy’s argument with an example of two hypothetical companies, A and B, that are entitled to receive $120/MW-day and $60/MW-day respectively as a result of the BRA. They both bid in the transition auction at $140/MW-day and $100/MW-day respectively. As PJM is required to accept the lowest bid, it takes company B’s bid, resulting in a $40 increase in the price, as opposed to a $20 increase had company A’s bid been taken.
Bay argues that because both companies are offering the same Capacity Performance product, “it simply permits consumers to be charged more in exchange for no additional benefit.” He lamented that “PJM’s methodology ignores the value of this opportunity.”
“This auction will impose a considerable cost on consumers for no additional reliability benefit,” the chairman said, warning that those costs could reach more than $1 billion. “Today’s outcome demonstrates the problems inherent in a complex, flawed design.”
Bay also dissented in FERC’s June order approving Capacity Performance. (See FERC OKs PJM Capacity Performance.) He noted that vote in his dissent to Tuesday’s order.
“I would not have agreed to transitional auctions at all, but having created them, it is the commission’s responsibility to ensure that they result in just and reasonable rates,” he said. “Unfortunately, that has not happened here.”
WASHINGTON — The D.C. Public Service Commission last week unanimously denied Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc., sparking applause in the hearing room and sending PHI shares tumbling on Wall Street.
“When this proposed merger is considered as a whole … we conclude that the joint applicants have not met their burden of persuading this commission that the proposed merger is in the public interest,” the three-member PSC said.
Upon the news, PHI shares dropped more than 18%, and Exelon stock dipped more than 3%.
In a joint statement, Exelon and PHI said, “We are disappointed with the commission’s decision and believe it fails to recognize the benefits of the merger to the District of Columbia and its residents and businesses. We continue to believe our proposal is in the public interest and provides direct immediate and long-term benefits to customers, enhances reliability and preserves our role as a community partner.
“We will review our options with respect to this decision and will respond once that process is complete.”
Exelon and PHI have 30 days to ask the commission to reconsider its 181-page order. The companies on Monday released a joint statement, saying they would continue working to complete the merger.
“We remain convinced the decision fails to recognize the substantial immediate and long-term benefits of our merger proposal to citizens, businesses and communities in the District of Columbia,” the companies said. “We want to deliver these benefits to customers and will strive to make that happen.”
Some analysts, however, are pessimistic about the deal succeeding. “While none of the negative items cited by the PSC in their order are glaring hurdles that could not be overcome, the magnitude of ‘small cuts’ appears in our view to suggest a deeper mistrust between the commission and Exelon,” UBS Global Research said.
Following their initial fall, the companies’ stock prices remained steady over the week, and Monday’s statement did little amid another bad day on Wall Street: Exelon closed at $30.75/share, down 2% on the day, while Pepco closed at $22.98/share, a less than 1% drop.
7 Factors of Public Interest
The PSC called the rejection “one of the most significant decisions” it would ever make, noting, “This proceeding has generated more interest and more active participation by parties and interested persons than any other proceeding in the commission’s more than a century of operations.”
The commission said it weighed the proposal on seven factors of public interest, among them the effects on ratepayers and shareholders, market competition and preservation of natural resources and the environment.
“The public policy of the district is that the local electric company should focus solely on providing safe, reliable and affordable distribution service to district residences, businesses and institutions,” Chairwoman Betty Ann Kane said. “The evidence in the record is that the sale and change in control proposed in the merger would move us in the opposite direction.”
Commissioner Joanne Doddy Fort concurred, saying, “The proposed merger would diminish Pepco’s ability to directly raise issues that address the needs of district ratepayers.”
Commissioner Willie Phillips voted to reject the merger application, but he dissented in a secondary vote to issue the actual order.
He agreed the proposed merger was a “bad deal” for the district, but said, “I am disappointed in the loss of the many opportunities inherent in the proposed merger that could have achieved benefits — tangible benefits — for our local communities and across the region.”
Surprise: Md. Wasn’t Biggest Obstacle
When Exelon proposed the deal 16 months ago, analysts predicted Maryland would be its biggest stumbling block. But after months of securing strategic alliances, Exelon won that commission’s 3-2 approval — albeit with 46 conditions. (See How Exelon Won Over Maryland.)
Meanwhile, in the district, opposition steadily stiffened. More than half of the Advisory Neighborhood Commissions and nearly half of the 12-member City Council opposed the deal. The Office of People’s Counsel and the attorney general’s office also advised against approval without significant concessions. (See Deadline Looms for Decisions in Exelon-Pepco Deal.)
As Kane read the commission’s summary of the order, there was a murmur in the room, as those attending the meeting realized that the commission was siding against the merger.
Many in attendance said they were surprised by the ruling, as they were prepared for the commission to approve the deal with concessions similar to other jurisdictions, such as Maryland.
“Honestly, I was pleasantly shocked. I commend them for their courageousness,” People’s Counsel Sandra Mattavous-Frye said of the commissioners. “It will have a domino effect on the entire proposal. The joint applicants have said they cannot go forward without D.C.
“The commission listened to the parties and, more importantly, they looked at the record,” she said, noting, “The applicants had the opportunity to supplement the record. They, too, heard the concerns being raised and chose not to address them.”
“I’m stunned,” said Anya Schoolman, executive director of DC Solar United Neighborhoods, a local solar power advocacy group. “I think … the commonly accepted wisdom was that they would approve it with conditions. And we were waiting to see how stringent those conditions would be.”
“I would almost go to say I’m shocked, because I fully expected that … the commission could have possibly come out in favor of the merger,” said D.C. Councilwoman Mary Cheh, who led the opposition in the district’s legislature.
“I’m just happy for the people of the District of Columbia,” she said. “The real beneficiaries of this, had this gone through, would have been the officers and the shareholders of Pepco and Exelon Corp. The people who would have been harmed are the ratepayers.”
“It was somewhat of a shocker that all other jurisdictions did in fact support this merger,” said D.C. Councilman Vincent Orange, who said he has remained neutral throughout the process. “At the end of the day, the Public Service Commission has ruled, and we’ll have to live with it and move on.”
‘David and Goliath’ Win
Power DC, which had organized opposition, said it was glad the PSC had “followed the will of the district’s electric customers.”
“The proposed acquisition would have been a substantial step backwards in the district’s efforts to move toward more sustainable electricity generation and greater reliance on local, renewable energy. It would have exposed D.C. residents and businesses to the risk of steeply rising electricity bills.
“Pepco has always affirmed its capability to provide a high level of service for its customers without this merger, and it has demonstrated a much greater willingness than Exelon to integrate new, customer-centered technologies.”
Mattavous-Frye called the win a “David and Goliath” scenario.
“I want to commend the public participation,” she said. “This was about consumer empowerment. People did not think their participation would be meaningful, and it is.”
Other Jurisdictions Approved Deal
The deal had been more than a year in the making. All of the other affected jurisdictions had approved it: Virginia, Maryland, Delaware, New Jersey and FERC.
Dave Bonar, Delaware’s Public Advocate, said the decision was a disappointment, but that it “doesn’t mean the deal is not salvageable.”
“They could appeal, or they could make more concessions,” he said. “Or they could just fold their tent and go back to Chicago.”
He said those who worked on getting Exelon’s concessions and reaching consensus were “disappointed.”
“We worked very hard to get this done,” Bonar said.
Critics in Md. Pleased
Mike Tidwell, director of the Chesapeake Climate Action Network, a group that intervened before the PSC in Maryland against the proposed merger, called the decision a “major victory” for the growth of clean energy across the region.
“One good idea that emerged from the proposed Exelon-Pepco (merger) was to create a PSC-guided process to explore ‘performance-based ratemaking.’ Utilities should be rewarded based on how well they perform on energy improvements that enhance our economy and reduce carbon emissions and climate change,” he said. “Hopefully, we can now move on to these solutions.”
Paula M. Carmody, People’s Counsel for the State of Maryland, had urged the state commission to reject the deal.
Last week, she said of its D.C. counterpart, “I think they got it right.
“They hit on the very issues identified in the proceeding before the Maryland commission,” she said, noting that the D.C. group had concerns about the “loss of local influence” over a utility with headquarters in Chicago.
Carmody, whose organization has one of three appeals pending before the Maryland commission, said she is not sure if the district’s decision is a death knell for the merger, “but clearly they can’t close” the deal as it stands now.
“It depends on what the companies do now,” she said. “They could appeal, they could file for reconsideration.” But, she said, the rejection makes the acquisition “problematic.”
A Win for Consumers, Environment
Roger Berliner, an attorney and Montgomery County councilman who had led that area’s opposition, applauded the D.C. PSC for standing up for consumers and the environment.
“As the testimony of countless expert witnesses made clear, Exelon has shown time and time again its interest in favoring its own nuclear generation holdings over renewable technologies like solar and wind, and the merger does far too little to provide benefits to ratepayers, while Pepco’s shareholders stand to benefit tremendously.”
The acquisition would have created the Mid-Atlantic’s largest electric and gas utility — and the country’s largest utility by customer count. Exelon has said the deal would boost its customer base to nearly 9.8 million from 7.8 million and increase its rate base to almost $26 billion from $19 billion.
SunEdison has begun construction on a 156-MW solar project near Pueblo, Colo. The company said it will be the largest solar power plant east of the Rocky Mountains.
The $253 million Comanche Solar project, which is scheduled to be completed in the first half of 2016, is being financed by tapping into a $1.5 billion line of credit, the company said. Xcel Energy subsidiary Public Service Company of Colorado will buy the energy under a 25-year power purchase agreement.
Public Service said it decided to buy the solar power over other energy sources, including natural gas-fired generation. “SunEdison, through the Comanche Solar project, is helping move us in the right direction,” said David Eves, president of Public Service. “It demonstrates that large-scale solar power can play an increasingly larger role in our customers’ energy future at a competitive price point.”
Dominion’s Ratepayer-Funded Donations Subject of AP Investigation
An Associated Press investigation has found that Dominion Resources billed Virginia residential customers for more than $1 million it spent in recent years on donations, including some to charities with close ties to influential politicians.
The wire service said it is legal in Virginia to charge ratepayers for the costs of charitable contributions, but lobbying expenses or political donations are not recoverable in rates.
The practice has attracted the ire of former Republican Attorney General Ken Cuccinelli. “Why should captive ratepayers, who have no option to get electricity from another company, be compelled to fund the charitable choices of a company?” Cuccinelli said. “Leave the ratepayers their money, and let them make their own charitable choices.”
Alliant Energy Reaches Agreement on Solar Field in Wisconsin
Wisconsin-based Alliant Energy is jumping into the solar energy market by signing a deal with a private solar farm in Beloit that could be running by early 2016.
Alliant announced last week it has reached a 10-year power purchase agreement with South Korean company Hanwha, which plans to build a 2.25-MW solar plant at a former landfill that’s part of the Beloit power-generation complex. Hanwha plans to build, own and operate the ground-mounted solar power field, which would sit on a 30-acre, capped landfill. Alliant said the facility will generate enough power to supply about 2,000 customers.
An Alliant spokesman said the solar facility could be running by early 2016, pending regulatory approval for construction and the power purchase agreement. The facility could be the largest solar power field of its kind operating in Wisconsin.
First Cross-Border Wind Farm Opens in Baja California, Mexico
A 155-MW wind farm in Mexico went into operation last week and is selling its power to Sempra Energy’s San Diego Gas & Electric, the first cross-border operation of its kind.
The solar facility is near the city of Tecate, in Baja California, and consists of 47 wind turbines. Power is exported through a new 4.8-mile transmission line.
Bloom, Constellation to Develop 40 MW of Fuel Cell Capacity
Bloom Energy has partnered with Constellation Energy to create 40 MW of fuel cell capacity at 170 installations on the East Coast and in California, where Bloom Energy is based.
The deal would double Bloom’s existing installed base. Bloom’s East Coast assembly plant is located in Newark, Del., on the previous site of a Chrysler assembly plant.
Duke Pushing for Smart Grid Battery Storage Standards
Duke Energy is joining the MESA Standards Alliance to push for new standards for smart grid technology and battery storage. The MESA (Modular Energy Storage Architecture) alliance was formed last year in an attempt to reach standards for interactivity between grid-scale battery storage and smart grid systems.
The goal is to develop a common methodology for joining grid-scale batteries with utility companies’ control systems, said Thomas Golden, Duke’s technology development manager. “We went out into the marketplace to see what standards are out there, and there wasn’t really anything beyond MESA,” he said. “What we get out of this is an opportunity to influence the standard we think will push the industry to the next level.”
A recent study predicted that 2015 will see about 220 MW of energy storage going into operation in the U.S., with more to come as utilities strive to reach renewable standards.
Startup Claims its Windows Produce 50x Energy of Traditional PVs
Startup SolarWindow Technologies has announced that its power-generating windows, which it claims can generate 50 times more energy than conventional solar panels, will hit the market within 28 months.
The technology can be applied as a coating to glass windows or plastic surfaces, where the film instantly generates electricity, the company said.
The coatings would be primarily organic, made from carbon, hydrogen, nitrogen and oxygen.
ACE, JCP&L and Rockland Electric Seeking Proposals for Solar Projects
Atlantic City Electric, Jersey Central Power & Light and Rockland Electric in New Jersey are accepting proposals for projects that will produce Solar Renewable Energy Certificates.
The companies are looking to obtain nearly 80 MW of SRECs.
They said net-metered projects up to 2 MW and grid supply projects certified to be sited on old landfills, brownfields or historic fill are eligible.
MISO last week revealed yet another twist in its deliberations over two southern Indiana transmission projects, leading some stakeholders to question whether RTO officials are following their planning rules.
In July, MISO said it would consider swapping the proposed 345-kV Duff-Coleman transmission project, estimated to cost $67.2 million, for a previously rejected Rockport-Coleman 345-kV transmission line estimated to cost $76 million. (See MISO Plan to Revisit Runner-up Tx Project Rekindles Shareholder Angst.)
PJM offered to share the cost of the latter project, which could solve stability problems at its Rockport substation. PJM’s contribution would reduce MISO’s spending on the line by about $29 million.
At last week’s MISO Planning Advisory Committee in Eagan, Minn., MISO staff proposed a “loop-in” giving the Rockport substation paths to both Duff and Coleman.
It’s attractive to PJM in part because the RTO needs two 345-kV circuits to its 745-kV substation. PJM officials say they have had stability problems at the substation because the area has added thousands of megawatts of generation but no new transmission since 1989. (See “PJM: Despite Lack of Cost Allocation Rules, MISO Project Too Good to Ignore” in PJM TEAC Briefs.)
“They need two lines out of Rockport. So we can build the original, single-circuit Duff-Coleman, loop it in, and that loop-in would give them two lines out — one to Coleman, one to Duff,” said Jeff Webb, MISO director of expansion planning.
Costs are still being studied, but MISO estimates the new alternative would add about $200,000 to the Duff-Coleman cost, an amount that would have a negligible impact on its cost-benefit ratio.
Shareholders, however, pressed MISO officials about the additional costs, asking whether customers would bear some of them. Webb said MISO would only agree if PJM picked up the costs of its benefits, holding MISO harmless.
If not, “then all bets are off and we’re going back to the original [Duff-Coleman] project,” Webb said.
But several stakeholders questioned whether MISO should be concerned with PJM’s needs in the context of MISO’s own need to address southern Indiana congestion problems. They also questioned whether MISO was following the proper processes in evaluating the expansions.
Kevin Murray of the Coalition of Midwest Transmission Customers asked why MISO was not constructing Duff-Coleman as a market efficiency project under MISO’s Transmission Expansion Plan (MTEP) and then evaluating Rockport-Coleman as an interregional project on its own merits.
“Well, because I think we have an opportunity here to be efficient about building out the grid on both sides without any harm to MISO,” Webb replied.
“You’re going to run into the same thing PJM ran into with Artificial Island,” Murray countered. “You’re pursuing an outcome where people are going to say you didn’t follow the process. And you’re going to get tied up in litigation at FERC and the customer is going to be the loser in all this because they’re going to end up paying for transmission congestion for a period in time when it doesn’t need to happen.”
He noted that other stakeholders, such as Northern Indiana Public Service Co., weren’t happy with the idea.
“NIPSCO objects to the fact that neither of the competing recommended projects … has been studied under the process specified by the MISO/PJM Joint Operating Agreement to determine cross-border benefits and RTO cost allocations,” NIPSCO said in a letter presented at the PAC meeting.
NIPSCO said the recent actions by MISO and PJM to modify the southern Indiana proposal “suggests that there are difficulties and inconsistencies” in resolving cross-border issues through current planning processes.
“Rather than address these issues, the RTOs have circumvented the defined JOA processes for an ad hoc solution,” the company said.
NIPSCO said the proposed projects should be studied under the JOA process using a joint MISO-PJM model.
David Davis of NextEra Energy asked whether MISO had the time to study the new proposal and allow for stakeholder review before the recommended projects in MTEP 15 are submitted to the MISO board Dec. 10. “It seems like that’s a pretty long putt,” he said.
Webb said he was confident that answers could be found within six weeks.
MISO’s Planning Advisory Committee last week deferred for a future meeting a vote on Wind on the Wires’ request to require external generators seeking network resource interconnection service to pay the dollars-per-megawatt portion of M2 milestone costs.
After a lengthy discussion, several stakeholders said they needed more information before voting.
Wind on the Wires, which represents the wind industry, argued that the M2 deposit should be applied to external generators because internal generators already put cash at risk to demonstrate that they are serious about moving forward. The deposits discipline generators to not jump in and out of the queue and cause re-studies, the group said.
MISO officials said they do not agree with Wind on the Wires’ proposed requirement for external units. They said not all internal generators pay an M2 deposit.
Two of three proposed MISO-SPP interregional projects touted to offer $235 million in benefits look much less attractive following additional modeling and are likely doomed.
MISO revealed the disappointing news at last week’s Planning Advisory Committee meeting, saying the new results indicate a disconnect in coordination between the two RTOs.
MISO and SPP staff worked for several months to find economic projects to relieve congested flowgates. At one point they had identified 70 such candidates.
New analyses appear to have doomed the Elm Creek-NSUB and S. Shreveport-Wallace Lake interregional projects. The Alto-Swartz 115-kV project continues to meet the benefit-cost threshold.
By June the list had been whittled down to three projects totaling $156.9 million near the RTOs’ seams in Kansas, Nebraska and Louisiana. (See 3 MISO-SPP Transmission Projects Move Forward.)
But the numbers turned out to be markedly different after the RTOs ran regional reviews that used different assumptions:
The Elm Creek-NSUB 345-kV project that previously showed $165 million in present value benefits over 20 years fell to $29.2 million in benefits. The benefit-cost ratio decreased to 0.89 from 1.22.
The rebuild of the S. Shreveport-Wallace Lake 138-kV line, which initially showed $46 million in benefits, is now projected at $2.7 million. The benefit-cost ratio dropped to 0.25 from 2.61.
The series reactor on the Alto-Swartz 115-kV line showed a slight benefit decrease — to $20.7 million from $23.4 million. The project originally was estimated to have an overall benefit-cost ratio of 4.32. Based on its $4.6 million share of the cost, the benefit-cost ratio for MISO is 5.98.
“The benefit-to-cost ratio for two out of the three projects did not meet the … criteria,” said Arash Ghodsian, technical advisor for economic studies at MISO. “We were not able to see the same level of congestion that we saw in the interregional models versus the regional.”
He said the interregional and regional models differed in their generation assumptions, the impact of MISO South’s industrial renaissance load growth and their handling of MISO Transmission Expansion Planning for 2015 and out-of-cycle projects. One key factor is differing predictions on generation retirements resulting from the Environmental Protection Agency’s Mercury and Air Toxics Standards.
“Are you saying MISO applied MATS retirement assumptions about SPP generation in the MISO model, but SPP did not have the same retirement showing in their model?” asked Cynthia Crane, principal regulatory analyst at ITC Holdings.
“That’s correct,” Ghodsian said.
Crane said the inconsistencies in the modeling is a “cause for concern.”
Ghodsian agreed. “It’s part of the process differences. Moving forward, we need to do better coordination between” MISO and SPP, he said.
The fate of the projects wasn’t officially determined at the PAC meeting. They will be discussed at next month’s PAC for potential recommendation “if any,” according to Ghodsian’s slide presentation.
MISO planners who just completed the third phase of a study on the Clean Power Plan said last week that a “multibillion dollar” transmission build-out will be necessary in almost every compliance scenario they’ve anticipated.
“Our final rule analysis will look to characterize the amount of that and the scope of it and what needs to be done. But we definitely see a big impact coming to the MISO system,” Jordan Bakke, senior policy studies engineer at MISO, told the Planning Advisory Committee.
Purple indicates economic generation that cannot be dispatched under state-level compliance with the EPA Clean Power Plan. Green indicates generation dispatched under state-level but not regional compliance.
The estimated costs for transmission expansion to meet compliance could be up to $10.8 billion in net present value over 20 years, according to the study.
“Transmission expansion will be needed to mitigate reliability impacts as well as economic congestion impacts of compliance. And a lot of this is driven by the level of coal plant retirements,” Bakke added.
The study also agreed with those by PJM and SPP in concluding that regional compliance with the Environmental Protection Agency’s carbon emission rule will be more cost-effective than if states go it alone.
MISO’s study concludes that a regional approach — including MISO, SPP, PJM, NYISO, the Tennessee Valley Authority, the Midwest Reliability Organization and the SERC Reliability Corp. in the Southeast — will save $4 billion to $11 billion in net present value over 20 years versus individual state compliance.
A sub-regional approach — through MISO’s North, Central and South areas — would save $2.5 billion to $11.5 billion over state compliance.
Coal Retirement, Transmission Needs Still Fuzzy
Planners said they won’t know how many plants will retire until they get a better read of the final EPA rule and get more feedback from stakeholders.
The analysis looked at five compliance scenarios, including increased cycling of coal units and higher utilization of combined-cycle units and combustion turbines.
The location of new gas and renewable generation will pose infrastructure challenges. Some of the new gas generation units, for example, will be located near existing gas pipelines but will be farther out from the existing transmission system. Generation will be coming from different parts of the system, “parts that the transmission system historically was not designed to fully deliver,” Bakke said.
Coal-to-gas conversions expected by 2030 under one scenario included in MISO’s analysis of EPA’s carbon emission rule. The scenario assumed that in addition to the 12.6 GW of MISO coal generation expected to retire under EPA’s Mercury and Air Toxics Standards, 25% of the remaining coal capacity in the Eastern Interconnection will convert to gas-fired combined cycle units.
The study found that the cost of adding electric and gas infrastructure for new or converted gas generators would be comparable regardless of the siting assumptions.
The study, which took more than a year, looked at candidates to relieve congestion identified in the draft rule analysis. In June, 107 congested areas were identified for potential economic transmission expansion. In July, that list was narrowed to 34 potential transmission projects related to the Clean Power Plan.
“This creates a first step,” Bakke said, adding that more potential transmission projects resulting from the rule will need to be reviewed.
Regional Approach More Cost-Effective
Another outcome of the study was confirmation that regional compliance approaches will be more cost-effective than more numerous, sub-regional approaches.
“We found this throughout our different phases that we looked at … It was more cost-effective from production cost standpoint, from a resource capital build-out — a variety of different metrics,” Bakke said.
Although the analysis is based on EPA’s draft plan and not the final rule, Bakke said the study allows MISO to “hit the ground running.”
Next, MISO will dive into more than 1,500 pages of the final rule and supporting documentation. “We’re confident that the generic or the overall framework is good, and we’re going to be taking feedback on how we can improve it going into our final rule analysis,” Bakke said.
Further Study Challenging
Stakeholders had a number of questions. Miles Taylor, an engineer at Northern Indiana Public Service Co., asked how MISO would deal with issues such as whether there might now be fewer coal plant retirements than some had expected initially.
Bakke said that while MISO looked at a variety of scenarios, it is hoping to get more specific feedback from stakeholders as they make more sense of the final rule in the months ahead.
George Dawe, vice president of Duke-American Transmission Co., representing the transmission developer sector, asked how MISO would assess the future if several individual states decide to go it alone rather than engage with a regional compliance solution.
Bakke replied that initial state plans are due to be filed just over a year from now. “We should at least have an indication going into that what states have planned to do.”
MISO said that if some states refuse to file a compliance plan, the RTO could make some modeling assumptions based on what EPA would likely prescribe for a state.
One thing that’s clear is that there’s an appetite for the information that MISO will gather in the next phase of its Clean Power Plan study. Darren Kearney, an analyst at the South Dakota Public Utilities Commission, said states will rely on the RTOs to help them understand the least-cost compliance options.
Bakke assured him that MISO will provide as much information as it can as soon as it can.
Discussions on how costs paid to SPP will be allocated within MISO will begin in September “on a separate track,” Eric Stephens, deputy general counsel, told members at the MISO Informational Forum last week. Stephens said confidentiality rules on the settlement talks prevented him from discussing specifics of the deal.
