Page 1691 – RTO Insider

January 12, 2016April 7, 2025

MISO Preparing a Place for Energy Storage in Tariff

By Amanda Durish Cook

CARMEL, Ind. — With one energy storage project under construction and several others being considered, MISO is beginning a look at rule changes needed to accommodate the emerging technology.

One fundamental question MISO will have to answer is whether storage will be considered generation or categorized as a transmission asset, MISO External Affairs Policy Advisor Jennifer Richardson said during a workshop at the Jan. 5 Market Subcommittee meeting.

“We’ve had kind of fits and starts with this issue … but as far as having a clear policy, well, that’s never happened,” Richardson said.

Last July, Indianapolis Power & Light began work on a 20-MW advanced battery, MISO’s first grid-scale storage array. The facility, located at the Harding Street Generation Station in Indianapolis, is expected to begin service in June. IPL’s parent, AES, has 116 MW of energy storage projects in operation and has 268 MW in construction or late-stage development globally.

MISO said it also has been approached by “several market participants who are considering battery storage options for the future.”

“I think what’s really noteworthy here is that there’s not a lot of precedent or cases here for MISO to determine whether this will be behind-the-meter or in-front-of-the-meter,” said Executive Director of Market Design Jeff Bladen, who added that the RTO wouldn’t encourage any method of energy storage over another.

MISO wrote short-term energy storage — such as batteries and flywheels, which can supply less than an hour of power — into its Tariff in 2009. Long-term resources such as pumped storage can provide energy, regulating and spinning reserves under the Tariff.

However, medium-term storage — battery and thermal storage that can provide hours of power — cannot serve as capacity, energy or contingency reserves under current rules.

“Medium-term storage is gaining a lot of interest,” said MISO Principal Advisor of Market Development and Analysis Yonghong Chen.

Chen said stakeholders need to discuss what sort of products MISO should provide. “Storage is a broad range of emerging technology … it can be complicated.”

MISO said CAISO, with 5,800 MW of storage in operation or development, is the most advanced region. ISO-NE, by contrast, has less than 1 MW of storage. PJM, which has about 200 MW of energy storage in operation, also has been considering rule changes. (See Treat Electric Storage Like Limited DR: PJM.)

“CAISO is certainly on one end of the spectrum and MISO may be somewhere in the middle. The issues that we’re looking for guidance on [are] really pretty vast,” Richardson said.

FERC also has been updating its rules to open ancillary services markets to more competition from storage. (See FERC Clarifies Energy Storage Rule.)

Josh Pack, manager of energy technologies at Vectren, said projects proposed by market participants can shape policy. “There are emerging business models and new market entrants helping to figure this out,” he said.

Wind on the Wires Executive Director Beth Soholt said policy should consider how independent power producers or utilities will be compensated. “It comes down to one question: ‘What do I get paid for?’” she said.

MISO is asking for a first round of written feedback on the issues raised in the workshop by Jan. 22.

Bladen said MISO plans to review the responses at the Feb. 2 MSC meeting. Tasks relating to policy formation may be delegated to either the MSC or Planning Advisory Committee, officials said.

January 12, 2016

Exelon Calls FirstEnergy PPA ‘Grossly Lopsided,’ Says it Can Offer a Better Deal

By Ted Caddell and Suzanne Herel

Exelon, which is seeking subsidies for its Illinois nuclear plants, has joined the opposition to FirstEnergy’s attempts to win guaranteed payments for its Ohio power plants. And it says it has a better offer.

In a filing with the Public Utilities Commission of Ohio, Exelon said regulators should reject FirstEnergy’s “grossly lopsided” power purchase agreement, proposing a competitive bidding process to supply the 3,000 MW for which FirstEnergy is seeking guaranteed rates (the combined value of FirstEnergy’s W.H. Sammis coal plant and its Davis-Besse nuclear station).

Exelon Director of Regulatory and Government Affairs Lael Campbell said the company would submit an offer providing “well over $2 billion in savings to Ohio families and businesses” compared to FirstEnergy’s proposed PPA.

“Today we are taking the unprecedented step of committing to offer into that competitive process at a price level that will guarantee billions in savings so that no one can misunderstand the gravity of the harm that would occur to Ohio customers if the commission approved” the FirstEnergy PPA, he said. “We are putting our money where our mouth is.”

The specifics of Exelon’s offer were redacted, but Campbell said it would be an eight-year fixed price for energy and capacity of about 3,000 MW that would come from “100% zero carbon resources” — nuclear, hydro, wind and solar facilities in PJM.

Exelon spokesman Paul Elsberg said there have been no further communications with PUCO regarding the offer.

FirstEnergy spokesman Doug Colafella said the Exelon offer ignores one of the fundamentals of the FirstEnergy offer — a way to secure power from in-state generators and the almost 1,000 jobs of those who work at the Sammis and Davis-Besse plants.

Exelon, he said, has “no plants in Ohio, no jobs in Ohio.”

AEP PPA

PUCO also is considering a settlement calling for eight years of guaranteed rates for some of American Electric Power’s plants. Exelon said time constraints prevented it from making a similar offer in that case.

“Exelon requested additional time to file testimony in the AEP case, but the motion was not granted,” Elsberg wrote in an email. “The arguments made by Exelon against the First Energy proposal apply equally to the AEP proposal.”

Last week, PUCO ruled that the Sierra Club, IGS Energy and Direct Energy must submit to questioning to explain why they are supporting the AEP proposal.

PJM Urged to Oppose PPAs

On Jan. 6, the PJM Power Providers Group (P3) and the Electric Power Supply Association sent a letter to the PJM Board of Managers urging the RTO to actively oppose the AEP and FirstEnergy PPAs, contending they would undermine PJM’s competitive electricity market.

Last month, PJM submitted testimony to PUCO, saying the PPAs needed changes to preserve competition and the state’s ability to attract merchant generation. PJM has said it plans to issue a market analysis of the PPAs this spring, but that may be after the commission renders a judgment. (See PJM Seeks Changes to AEP, FirstEnergy PPAs.)

P3 and EPSA said the RTO’s actions were too little, too late.

“In testimony recently submitted to the PUCO long after the cases were underway and the dangers known, PJM indicated that PJM did not take a position on these nefarious efforts to undermine PJM’s markets,” they wrote. “Rather than advising the PUCO on the devastating impacts to the market in the short and long term, PJM instead sent a message that these subsidies would somehow be acceptable if certain conditions were attached.”

The groups said that the RTO is leaving the commission to evaluate the proposals “in a vacuum.”

“PJM should not be afraid to say when a program being considered at the state level directly undermines the wholesale market,” it said. “One would expect that the Ohio commission, while reserving the opportunity to disagree, would welcome the input of PJM on the full ramifications of what has been proposed.”

The groups said the reliability and competitive prices provided by PJM “will evaporate if the market is corrupted by state actions that subsidize uneconomic units.”

PJM declined to comment on the letter.

Pablo Vegas, president and CEO of Ohio Power Co. (AEP Ohio), responded to the letter with his own to PJM, saying P3 and EPSA were wrong to accuse the company “of undermining the very markets AEP Ohio has long sought to support and improve.”

“AEP Ohio has carefully worked to confine the proceedings before the PUCO … to matters of retail rate recovery,” he said.

He noted that PJM historically has refrained from “intruding upon retail ratemaking proceedings — or attempting to influence retail policies,” and urged it not to deviate from that precedent.

In a Jan. 7 order, PUCO denied PJM’s request to be a late intervenor in the AEP case but invited the RTO to submit a friend of the court brief to outline its concerns and make recommendations.

Exelon’s Campbell said FirstEnergy was a champion of the competitive process until now. “Ironically, FirstEnergy led the drive to competition and up until this proceeding took positions before this commission and other agencies and public officials which embraced competition and retail choice,” Campbell testified. “FirstEnergy was right then; it is wrong today.”

Exelon Seeks Relief for Ill. Nukes

While it is opposing FirstEnergy’s PPAs in Ohio, Exelon is seeking relief for its nuclear generators in Illinois. The company has requested that Illinois expand its clean energy subsidies to include nuclear power alongside wind and solar energy.

A bill backed by Exelon stalled in the Illinois legislature last year. Those critical of the Exelon subsidies have called them a nuclear “bailout” and said they would cost ratepayers around $300 million annually in surcharges.

In November, Exelon announced it has delayed for a year a decision on whether to mothball its Clinton reactor. (See Exelon Defers Clinton Closure; MISO Hints at Changes.)

January 12, 2016

FERC: Spy Software Provides Evidence of UTC Scam

By Michael Brooks

An energy trading company’s use of employee-monitoring software provided FERC investigators with evidence documenting its strategy of making riskless up-to-congestion transactions to collect line-loss credits from PJM, officials said last week.

FERC last week issued a show cause order demanding more than $42 million from Coaltrain Energy (IN16-4).

The commission used email and instant messages in lodging similar allegations against Powhatan Energy Fund and City Power Marketing. FERC’s Office of Enforcement found an additional source of evidence in their investigation of Coaltrain — the company’s use of Spector 360, software that logs users’ every keystroke and automatically takes screenshots every 20 seconds.

The commission said Enforcement staff was tipped off to the software’s existence by a former Coaltrain employee in June 2012, almost two years after it had begun its investigation into the company. Coaltrain employees initially claimed they had forgotten about the software when Enforcement made its original data requests and repeatedly delayed releasing the logs when asked for them, FERC said.

When Enforcement finally gained access to the Spector 360 logs, they received a voluminous amount of information — about 10 GB per employee — detailing the company’s actions in the summer of 2010, including emails, instant messages, Internet search and browsing history and, perhaps most important, internal logs of every single trade the company made over that time period.

A Familiar Story

Prior to June 2010, Coaltrain specialized in UTC trading, correctly predicting the changes in spreads between PJM’s real-time and day-ahead markets. This “spread strategy” involved complex analyses of transmission constraints and the impacts on LMPs. The company was very successful at these legitimate trades, FERC noted, earning profits of $12.8 million in 2008 and $18.7 million in 2010.

Coaltrain changed its trading strategy once it learned it could make more money from PJM’s marginal loss surplus allocation (MLSA) program, which refunds a portion of transmission loss charges to companies who contribute to the fixed costs of the grid. (See FERC: PJM Entitled to Recoup Line-Loss Credits.)

The company “discovered that they could profit from MLSA payments alone if UTC price spreads could be minimized or avoided entirely,” FERC said. Coaltrain devised a new “OCL strategy” — “over-collected losses” being its internal term for MLSA.

The allegations are similar to those against Powhatan and City Power. In fact, FERC said, when PJM released a report on June 1, 2010, showing how much in MLSA it had paid to companies, the Spector 360 logs show that Coaltrain co-owner Peter Jones sent City Power founder Stephen Tsingas an instant message congratulating him on collecting nearly $16 million in credits.

A few days later, Coaltrain employees began searching PJM’s website and Google for more information on MLSA, the Spector 360 logs show.

From June 15 to Sept. 10, 2010, Coaltrain traded 4.61 million MWh, losing more than $96,000 on the UTC price spreads and $3.83 million in transaction costs. However, it collected $8.05 million in MLSA payments, resulting in a profit of about $4.12 million.

“In contrast to the spread strategy that involved a complicated analysis using congestion-based constraints, the OCL strategy did not rely on constraints at all,” FERC said. “While there is voluminous evidence showing that [Coaltrain’s] strategy was designed not to profit from price spreads but instead to capture MLSA, a contemporaneous comment from [Adam] Hughes — who designed the software tools [the traders] used to carry out their scheme — sums it up: ‘create application to find deals for loss credits.’”

Severe Penalties

FERC is seeking $38.25 million in civil penalties from Coaltrain, its two owners and four employees, along with the $4.12 million in profits.

Enforcement staff said that it is seeking severe penalties because Coaltrain lied to them about the information it had logged using Spector 360. In comparison, the commission has assessed $29.8 million in penalties against Powhatan and $15 million against City Power.

“Coaltrain misrepresented material facts about relevant documents in an effort to hide them from Enforcement and made false and misleading statements concerning those documents as well as the availability of their witnesses to testify,” FERC said.

Coaltrain issued a statement Tuesday insisting it “was always responsive” to FERC’s information requests.

“The existence of computer monitoring software was disclosed to FERC and its staff in filings at the commission in 2009, which is before the investigation even began. When asked for the materials, Coaltrain cooperated with its former vendor to obtain a new license and provide the information requested. Suggestions that there was any delay in responding to FERC are erroneous and uninformed by the facts,” the company said. “Coaltrain is eager to cooperate with FERC to resolve this matter and has cooperated at every step of the process.”

FERC noted that Coaltrain’s owners had terminated an employee in their previous company, Energy Endeavors, based on the information received through the software about his activities.

In 2009, Jones and fellow owner Shawn Sheehan discovered that employee Moussa Kourouma was attempting to form his own energy trading business, in violation of a non-compete clause in his employment contract. The owners were able to use Spector 360 to track Kourouma’s activity down to his bank transactions.

Based on this information, they were able to protest Kourouma’s filing for market-based rate authority for his new company to trade in PJM. FERC said that in a confidential affidavit attached to the protest, Sheehan said the information came from “a commercially available software program for monitoring employee use.”

“The company regularly used Spector 360, and any claims that they ‘forgot’ about it are false,” FERC said.

The commission issued a Notice of Alleged Violation in September. (See FERC Charges Third Firm with UTC Scam in PJM.) Coaltrain has until Feb. 6 to respond to the Order to Show Cause.

January 8, 2016

Md. Judge Upholds PSC’s OK of Exelon-Pepco Merger

By Suzanne Herel

A Maryland circuit court judge Friday upheld the state Public Service Commission’s approval of Exelon’s acquisition of Pepco Holdings Inc., denying an appeal led by the Office of People’s Counsel.

“The court’s scrutiny has revealed Order 86990 to be the product of substantial evidence supporting the conclusions and was clearly a rational review of the evidence by reasoning minds,” Judge Thomas G. Ross ruled.

The Office of People’s Counsel was joined in the appeal by the Sierra Club, Chesapeake Climate Action Network and Public Citizen. The parties had asked for the judicial review after Ross denied their request to stay the commission’s 3-2 decision. (See Md. Judge Denies Stay in Exelon-Pepco Deal.)

The petitioners had the support of Maryland Attorney General Brian Frosh, who filed a friend of the court brief asking that the merger decision be reconsidered.

People’s Counsel Paula Carmody could not be reached for comment Friday evening.

Exelon issued a statement saying it was “gratified” by the ruling.

“The commission correctly found that our merger proposal meets the requirements of Maryland law. The merger is in the public interest and provides direct, immediate and long-term benefits to customers, enhances reliability, promotes the growth of clean energy and increases Delmarva Power and Pepco’s roles as community partners.”

The petitioners asked the court to review five questions, among them whether the commission’s decision could be considered arbitrary because of its “unexplained conclusion that allegations of harm to the distributed generation and renewable energy markets were ‘speculative.’”

They also questioned the decision on several procedural matters and asked whether the PSC’s “failure to consider the acquisition premium in assessing the ‘no harm,’ ‘benefits’ and ‘public interest’ requirements of the Public Utilities article constitute an error of law.”

In the 12-page ruling, Ross shot down all of the concerns, saying the PSC had properly considered each issue. He sided with the commission in its opinion that merger opponents had “failed to articulate concrete examples” of public harm resulting from the deal.

D.C. is the last jurisdiction standing in the way of the $6.8 billion merger. The district’s Public Service Commission initially rejected the merger but agreed to reconsider the proposal after Mayor Muriel Bowser’s administration brokered a settlement.

Last month, the General Services Administration — the district’s largest consumer of electricity — filed a brief with the PSC saying the merger should be rejected unless it is retooled to include benefits for commercial customers. (See GSA Opposes Exelon-Pepco Settlement.)

The PSC is expected to make a ruling early this year. The deal has already been approved by FERC and regulators in Delaware, New Jersey and Virginia.

January 8, 2016

FERC Again Rejects Challenge to ISO-NE New Entry Pricing

By William Opalka

FERC on Thursday reaffirmed the zero-price offer requirement in ISO-NE’s new entrant pricing rule, again rejecting complaints by Exelon and Calpine that it unreasonably suppresses capacity prices and discriminates against existing resources (EL15-23-001).

The commission denied rehearing of an order from January 2015. (See FERC Upholds ISO-NE New Entry Pricing; Rejects Challenges by Generators.)

ISO-NE’s rule allows new resources to lock in their first-year clearing price for up to six subsequent delivery years by offering as a price-taker with a price of zero.

Exelon and Calpine argued that the rule creates a discriminatory two-tiered pricing scheme, with existing resources receiving lower prices than new ones if clearing prices fall in subsequent Forward Capacity Auctions.

The companies said the commission ignored the precedent it set in 2009 in rejecting PJM’s proposed zero-offer requirement, when it ruled that new and existing resources are similarly situated and should receive the same price (ER05-1410-013, et al.).

In its new order, however, FERC said its view has “evolved” since the PJM case, which was decided by members who have since departed the commission.

Because new resources have little maintenance needs, their going-forward costs are near zero, the commission said, and thus consistent with a zero-price offer strategy that ensures they continue to clear the FCA.

“Based on further consideration, the commission has realized that a zero-price capacity offer from a new merchant resource that has cleared in at least one previous auction and has incurred construction costs can be a competitive offer that reflects the resource’s going-forward costs, not an attempt to lower capacity market clearing prices,” FERC wrote.

The companies said ISO-NE’s new entry rule results in greater price suppression than PJM’s because of a longer lock-in period (seven years in ISO-NE, three in PJM) and broader eligibility. New England’s lock-in option is generally available to any new entrant, while PJM’s “applies only in narrow circumstances and thus is rarely triggered,” FERC said.

The order comes a month before FCA 10, scheduled for Feb. 8. The commission had said ISO-NE’s zero-price rule was acceptable because it used “differing clearing mechanics” than PJM’s. The companies said the disparate treatment is no longer valid since ISO-NE is introducing a sloped demand curve similar to PJM’s.

The commission acknowledged that the existence of the lock-in option “may result in lower capacity clearing prices” but said this was part of “a reasonable balance between incenting new entry through greater investor assurance and protecting consumers from very high prices.”

FERC said the relief the companies sought — requiring new entrants to submit offers higher than zero in subsequent auctions, as in PJM, or offering a lock-in option to existing resources — could raise costs.

“In a scenario where one or more new ISO-NE resources lock in their prices in year one, and auction clearing prices in subsequent years drop such that those resources do not clear at the year-one price, New England customers could incur significant costs to pay the lock-in resources out-of-market,” the commission wrote.

January 6, 2016

FERC Orders MISO to Change Auction Rules

By Amanda Durish Cook

FERC has ordered MISO to change the way it conducts capacity auctions beginning with the 2016/17 auction in April as it continues to investigate allegations of market manipulation against Dynegy (EL15-70).

While the commission didn’t rule on the issue of consumer refunds, several parties to the case predict such relief might be in the works.

“We find that the record shows that certain of the Tariff provisions governing market mitigation measures are no longer just and reasonable,” FERC wrote in its determination.

According to the commission, MISO stumbled on two fronts: The $155.79/MW-day maximum bid was too high for a “vibrant market” and needed to be set closer to $25, and MISO didn’t accurately gauge power exports. FERC said MISO’s current approach to determining capacity import limits doesn’t take into account counter-flows created by neighboring RTOs.

MISO has 30 days to file revised capacity import limits and set the initial reference level for capacity at $0/MW-day and 90 days to file Tariff revisions to develop default technology-specific avoidable costs ahead of the 2017/18 auction. The $0 default will replace MISO’s current practice of allowing offers based on the estimated opportunity cost of exporting capacity.

More Rulings to Come

More is to come on the matter, however, as the Dec. 31 order only addressed parts of the complaints brought forward by Public Citizen, Illinois Attorney General Lisa Madigan, the Illinois Industrial Energy Consumers and Southwestern Electric Cooperative that deal with Tariff provisions on the auction “given the limited amount of actionable time prior to the 2016/17 auction,” according to the commission. FERC is continuing its non-public investigation into the matter. (See FERC Launches Probe into MISO Capacity Auction.)

Public Citizen, the consumer advocacy group that filed the first complaint in May, called the ruling a “partial victory.” The group alleged that Houston-based Dynegy manipulated the April capacity auction by withholding capacity, resulting in prices clearing at $150/MW-day for the Zone 4 portion of Illinois, up to 40 times greater than clearing prices elsewhere in the footprint. The spike represented a nine-fold price increase in the zone compared with the year before and prompted FERC to call an October technical conference. (See MISO Stakeholder Process Under Scrutiny.)

Dynegy said it is “looking forward to working with MISO” to implement the changes mandated by FERC.

Spokesman Micah Hirschfield said it is “imperative” that the market construct in Zone 4 work with Southern Illinois’ competitive structure to avoid future retirements.

“Generators in Southern Illinois rely on the markets for revenues, unlike the traditionally regulated utilities in the neighboring states that embed their costs into their rates. Generation has, and will continue to, retire in Southern Illinois unless the market design reflects the competitive nature of the market, which has delivered lower costs to consumers than many of the neighboring states,” Hirschfield said.

Dynegy continues to maintain that it offered all of its megawatts into the April capacity auction “with no physical or economic withholding” and followed MISO’s Tariff.

MISO to Weigh Rehearing

FERC’s order that MISO set offers to a zero default elicited a critical reaction from MISO Independent Market Monitor David Patton, who said entering offers at $0 makes little economic sense. “I can’t imagine what the economic theory is behind that,” he said.

“We’re weighing whether to file for rehearing. I don’t know that we will because we argued all of this at the technical conference,” Patton said. He added that FERC and MISO seem to be employing separate economic principles, and that he will reach out to MISO to see how the Tariff will have to be revised to comply with the order.

“I think they recognize a problem, but at this point, [FERC is] unwilling to address it,” Patton said of FERC’s decision.

Refunds to Come?

The ruling has some groups anticipating refunds, and FERC has allowed for a refund effective date of May 28, 2015, the date of Public Citizen’s initial complaint.

“If FERC follows the logic of its New Year’s Eve ruling, and regardless of whether the commission finds Dynegy manipulated the market, then Illinois consumers will be in line for tens of millions of dollars in refunds,” Tyson Slocum, director of Public Citizen’s energy program, said in a statement.

Madigan also said refunds are in order. “It’s great news that FERC has acknowledged downstate electric customers deserve relief from an inflated and absurd pricing process. I am pleased with FERC’s decision to fix the auction rules, but FERC still needs to order refunds to consumers for the outrageously high prices,” she said in a press release.

FERC’s Ruling Limited

FERC stated in the order that MISO is under no obligation to modify zones or combine Zones 4 and 5. “Nevertheless, we encourage MISO to continue to work with its stakeholders to ensure its zonal boundaries reflect the physical realities of the transmission system,” the commission wrote.

FERC also determined that use of a sloped demand curve would not be addressed, as it falls outside of FERC’s response to the complaint. “We will not address potential revisions to MISO’s capacity construct, including a sloped demand curve, longer forward period and a minimum offer price rule, here because they are beyond the scope of these proceedings.

“However, we recognize that MISO is working with stakeholders to explore potential revisions to the capacity construct, including concerns specific to Zone 4, and we encourage them to continue doing so,” FERC wrote.

January 5, 2016May 27, 2025

Transmission, REV Dominate NYISO’s Landscape

By William Opalka

Bradley Jones, who stepped in as CEO of NYISO late last year, recently told RTO Insider that his three top initiatives “have always been transmission, transmission, transmission.”

He came to the right place. Transmission upgrades dominated activity in the NYISO footprint in 2015 and promise to occupy headlines in 2016.

The improvements are occurring amid a changing energy landscape. State officials and regulators are deciding how to handle aging and unprofitable power plants in western New York. Meanwhile, the Reforming the Energy Vision initiative seeks to encourage the growth of distributed and renewable resources throughout the state.

The New York Public Service Commission last month declared a public policy need for an expected $1.2 billion in upgrades to move 1,000 MW of power from upstate generation sites to load centers in and around New York City. The project has been discussed for more than three years; now, NYISO will seek bids on the projects. The PSC hopes to evaluate siting proposals by the end of the year, with approvals anticipated in 2017. The upgrades are expected to be in service in 2019. (See NYPSC Declares Public Policy Need; Directs NYISO to Seek Tx Bids.)

Future of Nuclear Uncertain

Will the transmission projects come too late to save aging and unprofitable nuclear and coal-fired power plants in the western part of the state? Or, as environmental and consumer advocates might ask: Are those plants even worth saving?

In his State of the State address on Jan. 13, Gov. Andrew Cuomo is expected to announce details of a plan to shift the state to 50% renewable energy by 2030, along with a strategy to keep the nuclear plants open until then by offering some financial recognition of their carbon-free emissions. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)

Nevertheless, Entergy is standing by its decision to close the James A. FitzPatrick nuclear plant on Lake Ontario in late 2016 or 2017.

Exelon and stakeholders are finalizing a reliability support service agreement for the R.E. Ginna nuclear plant that would run through March 2017 — after which, the company says, the plant is likely to retire. The PSC has extended the negotiating window for that deal to Feb. 29. (See Ginna Lifeline to End in 2017; Profits After ‘Unlikely’.)

At the same time, the state’s REV proceeding is continuing with development of demonstration projects, including microgrids and energy efficiency programs.

Much attention will be paid to the anticipated Track 2 Order that addresses rate design for the new business models. (See NYPSC Outlines Reforming the Energy Vision Changes.)

RMRs Winding Down

In the meantime, several reliability-must-run agreements that pay unprofitable plants above-market rates are starting to wind down. Some of the facilities hope to repower with natural gas, proposals that will be addressed by regulators this year.

One of these, the coal-fired Dunkirk station outside of Buffalo, was mothballed Dec. 31, when its RSSA expired. Owner NRG Energy has suspended the repowering plan pending resolution of a lawsuit filed by Entergy. (See NRG Plant Closures Could Impact Reliability in NY.)

The 312-MW Cayuga coal-fired plant outside of Ithaca is operating under an RSSA through mid-2017. Although its owner has proposed converting it to natural gas, a transmission project proposed by a distribution utility and endorsed by environmentalists could make the plant unnecessary.

Plans to convert the idled Greenidge power plant on Seneca Lake to gas are on hold as EPA has said it must undergo a “new source” review.

January 5, 2016

SPP, ERCOT Set New Wind Peaks

SPP, which has already set six wind peaks this fall, established another on Dec. 19 with 9,948 MW, the second time it has eclipsed 9,000 MW. The RTO said wind’s penetration level was 33.5%, off the record 38.3% set Nov. 4.

ERCOT closed out 2015 with its eighth wind peak of the year, a record 13,883 MW on Dec. 20, representing more than 93% of its installed wind capacity and 44.7% of load served.

The wind generation easily topped the previous peak set Dec. 19, when the ISO exceeded 13,000 MW for the first time with 13,029 MW.

ERCOT generated almost 4.4 million MWh of wind energy in November, accounting for 18.4% of energy used.

— Tom Kleckner

January 5, 2016

A Few Growing Pains for SPP as it Celebrates 75 Years

By Tom Kleckner

During the past two years, SPP has added new markets for its members, some 5,000 MW of peak demand and 7,600 MW of generating capacity in the Upper Great Plains, extending its footprint to the Canadian border in the process.

So what does it plan for an encore in 2016?

Celebrating its 75th anniversary, for one. SPP will mark the occasion this fall with several ceremonies and a commemorative publication chronicling the RTO’s history, which began in the days after the attack on Pearl Harbor.

That’s when 11 regional power companies in the Southwest — including predecessors of today’s SPP member companies — signed an agreement to pool their energy resources and ensure Central Arkansas’ aluminum production could maintain 24/7 operations. When World War II ended, an executive committee decided to continue the organization to maintain reliability and coordination.

From those modest beginnings, SPP has grown into a sprawling member-driven organization, coordinating electricity flows over 56,000 miles of high-voltage transmission lines across 575,000 square miles in all or parts of 14 states, from the Deep South to the Dakotas and westward. It counts 97 members representing cooperatives, power producers, marketers and independent transmission companies along with the usual transmission owners, and has 170 registered participants in its markets.

A ‘Success Metric’

SPP’s growth has been good news for its members.

The RTO projects the addition of the Integrated System (IS) last October will yield $334 million in member benefits over a 10-year period. It also has said the Integrated Marketplace — comprising day-ahead, real-time balancing and congestion-hedging markets — generated approximately $210 million in total regional net savings in its first year, in addition to $170 million in savings from SPP’s previous energy imbalance service market. SPP plans to release a study quantifying the transmission benefits its members receive in January.

“It’s been another interesting year for the corporation and our members,” SPP CEO Nick Brown said during October’s board meeting. “If ever there’s a success metric, it’s the members who have decreased costs or rates.”

SPP will focus much of this year on improving its rapidly maturing markets with three projects: enhanced combined cycle (ECC) logic, gas-electric “harmonization” and the Z2 crediting tool.

Improved Economic Dispatch

The ECC project is designed to provide more sophisticated modeling that captures the flexibility of combined cycle plants. Each combined cycle configuration will be modeled in the market-clearing engine as a separate resource.

SPP expects the increased flexibility to allow “optimization of the combined cycle resource configuration throughout the unit commitment processes,” projecting in its 2016 budget a $3 million to $5 million reduction in generation costs. The savings are expected to grow as new combined cycle plants join SPP in the future.

SPP has targeted March 2017 for completion of the $1.5 million project. (See “Enhanced Combined-Cycle Project Moves Forward” in SPP Board of Directors/Members Committee Briefs.)

The ECC work will be done in conjunction with system changes needed to close the Integrated Marketplace’s day-ahead market earlier and shorten the solution time for posting results by 30 minutes. Both have significant impacts on the market operating system’s solution time.

SPP said the gas-electric harmonization work will be completed by the fall, at a projected cost of $6.2 million.

The initiative is a result of FERC Order 809, which moved the timely nomination cycle deadline for gas from 11:30 a.m. CT to 1 p.m. (See “Board Approves Gas-Electric Timeline Change” in SPP BoD/Members Committee Briefs.)

SPP says the schedule changes are “an incremental improvement over the existing timeline.”

Years of Incorrect Credits

The Z2 crediting project dates back to the last decade as a result of years of incorrect credits for transmission upgrades. (See “Z2 Crediting Task Force Remains on Track” in SPP Markets and Operations Policy Committee Briefs.)

A project team is developing software that will properly credit and bill transmission customers for system upgrades under SPP’s Tariff attachment Z2. The problem has been avoiding over-compensating project sponsors and including a way to “claw back” revenues from members who owe SPP money for other reasons.

The task force has estimated creditable upgrades of $750 million, with up to $90 million in transmission customer improvements and the remainder from sponsored upgrades.

The task force hopes to present a better estimate during the Markets and Operations Policy Committee and Board of Directors/Members Committee quarterly meetings in January.

SPP says the new system should reduce errors, disputes and resettlements.

Eyes on Expanded Footprint

SPP’s day-to-day business in 2016 will remain focused on maximizing the addition of the IS to its footprint.

The IS tripled SPP’s hydroelectric capacity, which represented only 1.1% of the RTO’s capacity in 2014. It also added winter-peaking regions, increased seams coordination issues and greatly expanded the geographic area for SPP’s reliability monitoring function.

SPP says the addition of the IS has “opened opportunities to expand SPP’s services to affiliated entities in the Western Interconnect” through membership or contracted services. SPP has an ongoing market-consulting contract with the Northwest Power Pool, which has been exploring the possibility of opening an energy market for several years.

Because of the surge in wind production, the RTO will refresh its 2009 wind-penetration study in February.

Navigating the Clean Power Plan

SPP will continue its work helping states comply with EPA’s Clean Power Plan. The RTO expects “significant impacts in the near term and well into the future.”

SPP’s 2016 operating plan says it intends to encourage regional compliance. But it acknowledges some states may decide to go it alone. Several SPP states have joined litigation to block the rule.

“The lawsuits will muddy the water in terms of how SPP interacts with its stakeholders as they work to comply with the standards,” it said.

SPP’s 2016 operating plan says it intends to encourage regional compliance. But it acknowledges some states may decide to go it alone.

The RTO will include CPP compliance in the 2017 Integrated Transmission Planning 10-year assessment. A near-term transmission study also will be conducted this year, with the results presented to MOPC and the board in April.

At that time, MOPC and the board should be taking up for consideration SPP’s first Order 1000 project, the 21-mile, Walkemeyer-North Liberal 115-kV project in Kansas. An industry expert panel is currently evaluating responses to SPP’s request for proposals.

SPP expects to receive 3,200 proposals for competitive projects in 2016, double the number it saw in 2014.

It also expects a “significant increase” in generation interconnection studies. SPP projects a 12% bump in transmission volume to more than 407 MWh in 2016.

January 5, 2016

FERC Again Rebuffs Brayton Point Union

FERC on Wednesday denied rehearing of its June decision certifying the ninth Forward Capacity Auction results in ISO-NE, dealing another blow to a utility union’s claim that supply of the Brayton Point plant was illegally withheld to raise prices (EL15-1137).

The Utility Workers Union of America, which represents workers at the Massachusetts plant, in July asked FERC to void the auction results. (See Fourth Time the Charm? Brayton Point Union Again Challenges ISO-NE Auction.)

Energy Capital Partners, former owner of the 1,517-MW plant, did not offer it in capacity auctions for 2017/18 and 2018/19 after announcing the plant would close in 2017. Brayton Point was sold last year to Dynegy, which said it would close the plant as scheduled.

FERC previously rejected the union’s challenge to results of FCA 8 on similar grounds. FERC said a non-public investigation by its Office of Enforcement failed to uncover any evidence of wrongdoing.

“This conclusion remains valid for FCA 9,” FERC wrote.

The commission also reiterated its acceptance of the conclusion of ISO-NE’s Internal Market Monitor that no anti-competitive behavior existed before the auction.

FERC also rejected the union’s contention that the ISO-NE Tariff requires a determination that a unit is uneconomic before it is allowed to retire.

“The Tariff contains no provision requiring a resource to demonstrate that it is uneconomic before it is allowed to retire, and UWUA does not point to any such provision. There is no test as to whether the unit can economically provide capacity, nor is there a mechanism by which ISO-NE can compel the resource to continue operating under any circumstances,” the commission wrote.

— William Opalka