Page 1440 – RTO Insider

January 12, 2016

IPPs Challenge Dominion on Proposed Va. Generator

By Rich Heidorn Jr.

Independent power producers are challenging Dominion Resources’ bid to build a 1,588-MW combined cycle plant in the first major test of a 2013 Virginia law requiring utilities to demonstrate that they have considered “third-party market alternatives” to self-build projects.

Dominion Virginia Power filed its request for a Certificate of Public Convenience and Necessity with the Virginia State Corporation Commission in July, saying its proposed $1.3 billion plant in Greensville County was cheaper than any of the alternatives submitted in response to its request for proposals to fill the increased power demands it expects by 2019 (PUE-2015-00075). Evidentiary hearings on the proposal are scheduled to begin today in Richmond.

In a joint filing to the SCC last week, the Electric Power Supply Association and the PJM Power Providers Group (P3) challenged the fairness of Dominion’s RFP and its evaluation of the competing bids. They said regulators should deny Dominion’s request and order a new “open, broad RFP subject to independent review.”

The groups said Dominion’s RFP “was not designed to elicit competitive bids” but to satisfy the legal requirements to justify its self-build proposal. While the company had been planning a 3×1 combined cycle plant since 2011, the November 2014 RFP, which sought baseload/intermediate generating resources in service by 2020, gave competitors only six weeks to submit bids. They also contended the RFP included “unnecessary and overly restrictive” specifications regarding contractual terms, fuel supply and the plant’s location.

Internal Review

In its application, Dominion’s said its self-build proposal and responses from seven other bidders were impartially evaluated by a Dominion team separate from the staffers developing the Greensville plant. The proposals were judged on price and non-price metrics, including “economic impact, fuel strategy, facility reliability, bidder financial strength and environmental risks.”

The company called the Greensville power station “the clear economic and operational choice” as the next required resource for its long-term needs, saying it would save customers $2.1 billion in net present value compared to purchases from the PJM wholesale market.

“It will support a continued balance of demand and supply resources, in addition to wholesale market purchases, and will serve as a prudent addition to the company’s generating fleet,” Dominion said.

If approved, the Greensville plant would be the third combined cycle plant built by Dominion in five years.

The company said it is projecting peak load growth of approximately 4,580 MW in the Dominion zone over the next 15 years, an average increase of 1.5%. PJM’s 2015 load forecast identified the zone as the fastest growing in the RTO because of its popularity as a site for energy-hungry data centers. (See Changes to PJM Load Forecast Cuts Benchmark Peaks.)

The plant would boost Dominion’s rate base. The company proposed a revenue requirement of $41.6 million per year based on a 10% return on equity. SCC staff said the requirement should be cut by $2.5 million based on an ROE of 9.25%.

EPSA and P3 said the SCC should require a neutral, third-party evaluation of bids because the utility has a conflict of interest.

“The notion that Dominion employees can impartially review the company’s own proposal simply because they were not on the ‘self-build team,’ along with the company’s conclusion that its option represents a net present value savings of $1.5 [billion] to $2.304 billion compared to the alternatives evaluated, are suspect at best,” the groups said. “There is nothing in [the company’s] testimony that gives us any idea of what the company actually did to evaluate alternatives.”

The company’s two proposals received scores of 4.52 and 4.54 on a 5-point scale, while the highest scoring of the seven competitive bids received only a 3.3 rating.

SCC Staff Noncommittal

The groups were also critical of the SCC staff, saying it “has not undertaken a critical analysis of Dominion’s conclusions regarding its analysis of market alternatives.”

Marc A. Tufaro, a principal utilities analyst in the commission’s Division of Energy Regulation, filed testimony Nov. 20 saying the Greensville plant “is expected to have the lowest total cost when dispatched in excess of a 20% capacity factor.”

Tufaro did challenge the company’s projected savings, saying its forecasts of fuel prices, market purchase prices and other factors were “extremely difficult to predict with a high degree of accuracy.”

Tufaro said whether Dominion adequately considered third-party market alternatives was “a difficult question to answer,” expressing no opinion.

“Should the commission determine that the company has adequately considered third-party market alternatives, staff is not opposed to the approval of a CPCN for Greensville.”

Tufaro said “no respondents or comments [were] filed by the public contesting” Dominion’s conclusion Greensville was a better option than any third-party alternatives. EPSA and P3 said Tufaro ignored testimony by a consultant to environmental groups who they said criticized “the limited scope” of Dominion’s RFP.

2013 Law

The Virginia General Assembly amended the state Electric Utility Regulation Act in February 2013 requiring that a “utility seeking approval to construct a generating facility shall demonstrate that it has considered and weighed alternative options, including third-party market alternatives, in its selection process.”

In October 2015, the SCC rejected Dominion’s proposed 20-MW Remington solar facility, ruling that the evidence submitted by the company — an analysis of North Carolina’s solar market — was insufficient because the resources the company considered were already committed.

The commission said a “serious and credible RFP process would certainly be relevant to whether a CPCN applicant has met the code’s requirement to consider and weigh third-party market alternatives in the company’s selection process; however, we do not need to rule herein that a formal RFP must always be performed in a CPCN case in order to fulfill the demonstration required by [the law] regarding alternative options, including third-party market alternatives. There may be other credible methods to meet the statute’s requirement.”

January 12, 2016January 29, 2024

MISO: Redispatch Key to CPP Compliance Through 2025

By Tom Kleckner

LITTLE ROCK, Ark. — MISO’s 15 states may be able to comply with the Clean Power Plan through 2025 by redispatching the RTO’s generation fleet, according to early modeling by RTO staff.

David Boyd, vice president of government and regulatory affairs, told officials of Arkansas’ Department of Environmental Quality and Public Service Commission on Jan. 5 that MISO has been conducting modeling exercises in three “discrete tranches.” The first analysis, due to be completed in February, was conducted to help the RTO understand how it might help its footprint reach compliance.

“It looks like we can be compliant as a region through 2025, primarily through dispatching energy,” Boyd said in discussing the preliminary results. “We believe we can use the new resources coming online and existing resources to reach compliance.”

Boyd told the joint stakeholder meeting that the study is based on a “viable trading scheme” within its region. He said MISO is also conducting individual state-by-state analyses and an evaluation of leakage’s effect on generation dispatch.

“As we look forward with state [renewable] standards, bringing more wind resources online, state energy efficiency programs … we’ll be all right,” Boyd said.

Boyd said more information is forthcoming at the Jan. 20 Planning Advisory Committee meeting. MISO staff told the PAC in December that a flexible compliance strategy that mixes generation resources and trading programs will lower compliance costs. (See MISO: Coal Retirements, Gas Prices, Flexibility Key to CPP Compliance Costs.)

Boyd told the group that changing MISO’s dispatch processes by incorporating carbon costs could “lead to an increase in the cost structure of electricity.”

The ADEQ and APSC — which are jointly developing the state’s response to the CPP — have been gathering comments and feedback. The state’s comments on the CPP are due to EPA by Jan. 21. Arkansas and other states face a Sept. 6 deadline to submit either an implementation plan or an extension request to EPA; states that don’t meet the deadline run the risk of having a federal implementation plan imposed.

ADEQ Director Becky Keogh reminded the group that Gov. Asa Hutchinson has directed them to find the least-cost compliance method. At the same time, Arkansas’ attorney general has joined the multistate litigation against the plan.

“Arkansas is continuing to pursue a dual-strategy approach that involves communications with other state agencies, the attorney general’s office and the governor’s office,” said Stuart Spencer, the ADEQ’s associate director of air quality. “While we still plan to enter comments, we’re mindful our attorney general has entered litigation.”

The stakeholders were joined by Sarah Adair, a senior policy associate with Duke University’s Nicholas Institute for Environmental Policy Solutions, who has been crisscrossing the country convening regional dialogues on the CPP. She described the pros and cons of the mass- and rate-based compliance approaches.

Several stakeholders noted the absence of a reliability safety valve in the federal implementation plan. “My understanding of how EPA would approach reliability would be to work with FERC on the federal plan” in the same way states are required to demonstrate they considered reliability in developing a state plan, Adair said.

“The EPA says in the final rule [it’s] not worried about reliability with a trading system,” she said. “With the allowances or credits, companies can always go out and buy more credits if they need to run a unit more.”

The flexibility of trading, which does not limit emissions from any particular unit, “inherently addresses the issue of reliability,” Adair said in an interview.

January 12, 2016

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, 2016

LS Power’s Artificial Island Rate Filing Challenged

By Suzanne Herel

The Delaware Public Service Commission, the Delaware Municipal Electric Corp. and American Municipal Power are protesting the formula rates proposed by LS Power’s Northeast Transmission Development for the Artificial Island project (ER16-453).

Northeast Transmission “has failed to demonstrate that its proposed return on equity [ROE], formula rate protocols, process for using a projected transmission revenue requirement, capital structure approach, depreciation rates or incentives are just and reasonable,” the PSC wrote.

The protesters asked FERC to suspend Northeast Transmission’s filing for the maximum of five months and conduct an evidentiary hearing on the matter.

Northeast Transmission is a subsidiary of LS Power, which PJM chose to build a stability fix for the the Salem and Hope Creek nuclear reactors in New Jersey. (See PJM Board OKs LS Power’s Artificial Island Project Despite Objections.)

In its 810-page, Dec. 2 filing, the company requested that FERC approve its annual transmission revenue requirement and five categories of transmission rate incentives — including 100 basis points in adders for participation in PJM and “the increased risks and challenges” of the project — effective Feb. 1. It asked to replicate the rate and incentives for future projects conducted by yet-to-be-formed affiliates.

In its protest, the Delaware Municipal Electric Corp. took issue in part with the proposed 10.5% base ROE, which it called “unjustified and inconsistent with commission precedent.” It also criticized the company’s request for a 50-basis-point adder for participation in PJM as unwarranted. If awarded, the adder should not take effect until the project goes into service, expected to be June 1, 2019, it said.

AMP also challenged Northeast Transmission’s proposed ROE and depreciation rates. It asked that FERC issue a delinquency filing requiring the company to provide additional information supporting its income tax calculations and post-employment benefits expense and said it would participate in any settlement judge procedures.

The project will consist of a new 230-kV transmission line between the Salem substation in New Jersey and the 230-kV Red Lion-Cartanza and Red Lion-Cedar Creek transmission lines in Delaware by way of the newly constructed Silver Run substation. Northeast Transmission will construct the river crossing, with Public Service Electric & Gas and Pepco Holdings Inc. doing related substation and connection work.

PJM’s proposed cost allocation, which would bill nearly all of the $146 million price tag to consumers in Maryland and Delaware, will be the subject of a Jan. 12 FERC technical conference. The conference will “explore both whether there is a definable category of reliability projects within PJM for which the solution-based DFAX [distribution factor] cost allocation method may not be just and reasonable, such as projects addressing reliability violations that are not related to flow on the planned transmission facility, and whether an alternative just and reasonable ex ante cost allocation method could be established for any such category of projects,” FERC said (EL15-95). (See FERC Questions Fairness of Artificial Island Cost Allocation.)

January 5, 2016

SPP Report Shows 16% Decrease in Coal Generation

SPP has seen a 16% drop in coal-fired generation over the last two years, thanks in no small part to consistently low gas prices.

The SPP Market Monitoring Unit’s quarterly market report for September-November said coal-fired resources accounted for 52.1% of generation in the fall of 2015, compared to 62.7% in 2013, the last few months of SPP’s energy imbalance services market.

spp The Monitor noted the decline in coal generation has been offset by increases in wind (up 3.7%), nuclear (up 3.4%) and combined cycle generation (up 3.3%). Hydro generation increased 2.1% over the two-year period, primarily because of the addition of the Western Area Power Administration-Upper Great Plains.

According to the report, Panhandle Hub gas costs averaged $2/MMBtu in November. Average gas prices for the fall were $2.25/MMBtu, compared to $3.76/MMBtu in 2014.

Average LMPs for both the real-time balancing market and the day-ahead market also saw significant declines. Real-time LMPs averaged $20.73/MWh (-$8.84 from fall 2014) and day-ahead LMPs averaged $19.98/MWh (-$8.19).

Lower prices were “prevalent in the north due to less expensive generation” and in the west-central due to the area’s “abundant low-cost wind,” the report said.

The MMU said SPP is experiencing divergence between day-ahead and real-time prices, partially because of “significant price volatility” in the real-time market.

— Tom Kleckner