FERC ruled on Thursday for the third time that an allegation of “price suppression” in the capacity market was outside of the scope of an ongoing proceeding to review a proposed agreement to prop up the struggling R.E. Ginna nuclear power plant in New York (ER15-1047).
Because the rehearing order reaffirmed FERC’s stance on the price suppression issue in its original order on Ginna, “we find that TC Ravenswood’s request for rehearing is improper and we will dismiss it,” the commission said.
BALTIMORE — Delaware Public Service Commission Chairman Dallas Winslow took on PJM planners over the Artificial Island project and rival developers sparred over the enforceability of cost caps at a panel discussion on Order 1000 implementation at last week’s Organization of PJM States Inc. annual meeting.
Opening up the session, PJM Vice President for Planning Steve Herling talked about how Order 1000 has increased planners’ workload and noted how cost allocation, “previously an end result of the process, is now getting fed into the process at the beginning.”
A slide in Herling’s presentation elaborated, saying that stakeholders are attempting “to influence our decision-making based on who will pay rather than which project is the most cost-effective.”
That didn’t sit well with Winslow. “I’m not sure a project can be cost-effective if it doesn’t cost the appropriate parties the burden of what they’re benefitting from,” he said.
Winslow called for a show of hands from other state regulators, asking: “What state in the room here would agree to pay voluntarily a cost allocation that made you pay 80% of the cost when you got 20% of the benefit?”
No one raised their hand.
While he didn’t mention the project by name, Winslow’s comments were a clear reference to the dispute over the cost allocation for the Artificial Island stability project.
Because the project is considered a lower-voltage facility, the cost of LS Power’s plan — running a new 230-kV circuit from Salem, N.J., under the Delaware River to a new substation near the 230-kV corridor in Delaware — is being allocated almost entirely to Delaware and Maryland customers.
In an Oct. 9 filing in response to complaints from those states, PJM acknowledged that the cost allocation may “appear disproportionate” but took no position on whether FERC should reconsider the use of solution-based distribution factor (DFAX) methodology for divvying up the bill on such projects (EL15-95). (See PJM: Artificial Island Cost Allocation Appears ‘Disproportionate.’)
Winslow called on PJM and its stakeholders to address the equity issues he said were raised by the dispute.
“There are times when you’ve got to stand up and say ‘is this is fair or not?’” Winslow said. “Should we just kick it down the road to Washington D.C.? Or should there be a mechanism to address what clearly and objectively is a violation of law?”
Last year, PJM planners recommended Public Service Electric & Gas be selected to construct a different solution for Artificial Island. PSE&G’s winning proposal was estimated at $1.066 billion before planners eliminated two 500-kV lines from it.
Facing a barrage of criticism, PJM’s Board of Managers rejected the proposal and reopened the project, allowing PSE&G and two other finalists to revise their proposals in response to LS Power’s offer to cap its project cost at $171 million — $40 million to $90 million less than the PSE&G project.
The bitter feelings over that battle were apparent at the panel discussion as Jodi Moskowitz, senior director of transmission development and strategy for PSE&G, suggested a developer might be able to recover costs above its cap if it can be shown to have acted prudently.
“FERC has yet to approve a cost cap coming out of an Order 1000 process. So we’re not sure at this point if cost caps are in fact legally enforceable,” she said.
She noted that ITC Holdings has asked FERC for guidance on whether a cost cap constitutes a just and reasonable rate. Because the commission hasn’t ruled, she said, “it is still very much an open question.”
LS Power’s Sharon Segner insisted the cap it agreed to was enforceable, saying it will be included in the designated entity agreement with PJM.
Workload Increasing
Herling said the volume of transmission proposals unleashed by Order 1000 has strained PJM’s resources.
“Most reliability projects — 90% or more — are solved by relatively simple upgrades to existing infrastructure. And we would typically have worked in a collaborative fashion with the transmission owner to identify one or two options to solve that problem,” he said. “Now we’re getting four, five, six — as many as 26 — proposals to solve a given problem.”
Herling said it added to the workload of not only the planners conducting the analyses but also the RTO’s legal and finance staff, who help administer the process.
Herling noted that CAISO and SPP have sought to reduce the workload by eliminating the sponsorship approach: “Simply pick the best solution and put it out for bid.”
But he said PJM wasn’t willing to abandon the sponsorship model yet. “We see a lot of value in the sponsorship process,” he said.
FERC on Thursday denied rehearing of its approval of Constellation Energy’s acquisition of five New England power plants, a deal proposed five years ago (EC10-85).
NSTAR Electric challenged the sale of five power plants in the Boston area worth about 2,654 MW from various entities to Constellation for $1.1 billion. The sale represented about 8% of the generation fleet within the ISO-NE footprint at the time.
NSTAR claimed that the deal would harm competition in the New England energy market. FERC, however, approved the transaction as in the public interest.
NSTAR requested a rehearing, saying in part that two gas-fired plants originally owned by Mystic Power were susceptible to common mode failure because they both depended on a connection to a Distrigas liquefied natural gas terminal for their fuel. This condition, NSTAR said, could lead to the simultaneous loss of fuel supply, which would drive up consumer costs due to an increased reserve requirement by ISO-NE.
FERC in its order last week said this infrastructure issue was outside of the scope of the acquisition and noted that a 2006 settlement regarding the issue imposed conditions on the plant owners and subsequent buyers.
While the FERC docket for the case has been dormant since June 2011, when Constellation filed a response to NSTAR’s complaint, the companies have undergone significant changes of their own.
Original plaintiff NSTAR merged with Hartford, Conn.-based Northeast Utilities in April 2012 to create the region’s largest distribution utility that has since been renamed Eversource Energy.
Constellation was acquired by Exelon in March 2012. In 2014, Exelon sold one of the plants in the original deal, the 688-MW Fore Generating Station, to Calpine for $530 million, marking that company’s entry into New England.
FERC last week set Entergy Corp.’s ninth annual allocation of its operating companies’ 2014 production costs for hearing and settlement procedures (ER15-1826).
As it has in years past, FERC said Entergy had not proven its proposed rates were just and reasonable. It accepted the proposed rates and made them effective June 1, 2015, subject to refund pending the hearing and settlement procedures.
The commission also issued three orders in long-running disputes regarding Entergy cost allocations for a portion of 2005, setting one issue for hearing and settlement procedures and rejecting two rehearing requests.
Bandwidth Remedy
At issue is how Entergy allocates production costs among its half dozen operating companies under its system agreement. The companies essentially operate as one system, although each has different operating costs.
Payments are made annually by low-cost operating companies to the highest-cost company in the system, using a “bandwidth” remedy that ensures no operating company has production costs more than 11% above or below the Entergy system average.
Regulators in Entergy’s states have regularly challenged the annual bandwidth filings. Entergy’s proposed rates for 2014 drew protests from the New Orleans City Council and the Louisiana and Texas commissions.
FERC gave the administrative law judge overseeing the case discretion to combine the proceeding with the previous four years of disputed annual cost-allocation cases, which were consolidated in December. (See FERC Bundles Entergy ‘Bandwidth’ Disputes for Hearing.)
2005 Calculations
The three other orders concern Entergy’s first cost-allocation calculations, for a seven-month period in 2005.
It denied a request from the Arkansas commission to exclude Entergy Arkansas from making payments and an Entergy compliance filing for hearing and settlement procedures (EL01-88-013).
FERC had rejected a 2011 compliance filing because it used six months of data to recalculate the seven-month period. The company responded with a more comprehensive recalculation report it said were based on the actual books and records of each operating company.
The New Orleans City Council and the Arkansas and Louisiana commissions all protested. The Arkansas Public Service Commission argued the compliance filing should be rejected because it assumed Entergy Arkansas would make further bandwidth payments, even though the company had withdrawn from Entergy Corp.’s system agreement in December 2013.
FERC said that it had never indicated that Entergy Arkansas should be exempt from the bandwidth calculations for that period.
Interest Payments Required
The commission also rejected the Arkansas commission’s argument that the bandwidth payments — $167.3 million, plus $56.5 million in compounded interest — amounted to “exit fees,” saying the payments were “obligations specifically required by the system agreement and are for a period when Entergy Arkansas was subject to the system agreement.”
(FERC Commissioner Colette Honorable, a former member of the Arkansas PSC, did not participate in the order.)
The commission also denied Entergy’s request for rehearing of an earlier order rejecting a compliance filing (EL01-88-012) and one issued in response to a ruling by the D.C. Circuit Court of Appeals (EL01-88-011), ordering Entergy to include interest on recalculated bandwidth payment amounts from the seven-month period.
FERC disagreed with Entergy’s contention in the compliance-filing request that the commission had failed to adequately explain its decision to require interest. Interest, the commission said, ensures that “the recipient receives payment in inflation-adjusted dollars.”
LITTLE ROCK, Ark. — SPP rolled out a flashy, redesigned website last week, culminating several years of effort and months of planning, development and testing.
Designed with non-RTO users in mind, the website adapts to the user’s screen size, from flat-screen monitors to tablets and smartphones. Its home page features a real-time price-contour map as well as graphs of generation mixes and load forecasts, all updated every five minutes.
“We laid out the site and organized the site with people other than subject-matter experts in mind,” SPP’s Derek Wingfield told the Markets and Operations Policy Committee last week. “It’s written in a way that’s understandable to them.”
Wingfield said links to frequently used business-critical pages are prominently displayed on the new home page: the Stakeholder Center, Engineering, Markets & Operations and Regional Entity.
Users will be able to create an account to simplify the meeting registration process. Once a user creates a profile, the user’s information is stored and auto-populated when signing up for conference calls or for online and in-person meetings.
However, only meeting registrations through mid-November will be carried over from the old site. Users will have to re-register for any meeting scheduled 30 days or more after the website’s Oct. 15 go-live date.
Wingfield said SPP has improved the website’s search functionality, calendar and document library, which were frequent targets of stakeholder criticism. SPP’s Tariff will still be available in its old format, but the Regulatory and Legal Group page has added a “Notable FERC Filings” link to better sort regulatory dockets.
A link has been added to the home page that explains the new website’s layout and major features.
BALTIMORE — PJM Market Monitor Joe Bowring said last week that the RTO must include strong market-power protections in rules allowing generators to change their offers hourly.
Bowring also told a meeting of the Organization of PJM States Inc. Advisory Committee that he is concerned that the Monitor has no defined role in screening generator offers under the new Capacity Performance rules.
The annual meeting of the OPSI Advisory Committee is the one time per year that the Monitor and the PJM Board of Managers meet publicly face-to-face. Both Bowring and PJM Chairman Howard Schneider agreed that their relationship is strong despite their frequent disagreements on Tariff filings.
“I think part of maintaining the positive relationship we’ve had with PJM over the years is understanding exactly what our roles are,” Bowring said.
And that, he said, is why he is raising his concerns that the CP rules give the Monitor no formal role in evaluating physical parameters in offers from generators.
Although the process approved by FERC requires PJM to consider the Monitor’s input, Bowring said he would prefer a parallel review process similar to that used in determining generators’ avoidable cost rate, with PJM ensuring compliance with its Tariff and the Monitor screening for market power. (The ACR of a generation resource is the fixed costs necessary to allow a generation resource to remain in commercial operation.)
“Our process can be much more contentious than PJM’s. It’s a very different standard,” he said.
If the Monitor disagrees with PJM on physical parameters under CP, Bowring said, “it could get messy.”
“I think it’s better to have a clear process where everyone understands what will happen in the event there’s a disagreement. And it’s highly likely there will be one — there are different standards being applied.”
Board Member Jean Kinsey said she thinks the process proposed by PJM and accepted by FERC should be given time to work.
“The process that’s being used for PJM and the Market Monitor to jointly sit down and see the physical parameter data that’s being submitted simultaneously is, it seems to me, a very good process because … you’re collaborating on your thoughts about whether it’s good, bad or indifferent,” Kinsey said. “These are physical parameters. They’re more engineering-centric than the cost-based [parameters]. … If a year from now, a year and a half, it seems not to be working, we will re-address it just like we do everything else.”
Market Power Concerns
Bowring also said that while he supports a move to allow generators to change their offers hourly, he is concerned that it could lead some to exploit weaknesses in PJM’s market power mitigation rules.
In June, FERC ordered PJM to change its Tariff to allow generators to submit day-ahead offers that vary by hour and to update their offers in real time (EL15-73). PJM is the only RTO that doesn’t allow such variable offers. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)
PJM must make a compliance filing spelling out how it will implement the change by Nov. 1. The Generator Offer Flexibility Senior Task Force will be meeting Wednesday to discuss the proposal.
He said the introduction of hourly offers has impacts on both local market power — which PJM polices through the three pivotal supplier test — and aggregate market power.
“There are various ways to game the three pivotal supplier test and the impact of that is going to be made much worse with hourly flexibility and hourly offers unless they’re addressed,” he said.
Aggregate market power concerns arose during the January 2014 polar vortex, when Bowring said “just a couple” of generation owners were pivotal — PJM needed their output in order to clear the market.
“In PJM there is no rule governing aggregate market power,” Bowring said. “That’s been fine to date, but with the hourly market flexibility it’s not going to be fine anymore.”
Bowring’s suggestion: “If you change your offer in midday to reflect gas costs, that’s fine. But you should not be allowed to increase your markup from $10 to $500 because you think the market is tight, you’re pivotal and you can get away with it.”
Aligning the eligible trading points for increment offers (INCs) and decrement bids (DECs) with nodes where generation, load or interchange transactions are settled, or at trading hubs;
Altering the biddable locations for up-to-congestion transactions (UTCs) to generation buses as sources only, trading hubs, load zones and interfaces; and
Allocating uplift to UTCs consistent with INC and DEC transactions.
PJM said it proposed the changes to stimulate stakeholder discussion. “The goal of this discussion is to retain all of the positive aspects that virtual transactions bring to the market while removing the bulk of the issues that they can create when used inefficiently under the existing rules.”
An overview of the report will be presented at the Oct. 22 meeting of the Markets and Reliability Committee. The study also looks at the purpose of virtual trading, the mechanics by which such trades are offered and cleared, potential problems that can arise and examples of how market participants use them.
Virtual transactions have been incorporated in PJM energy markets since the June 1, 2000, inception of the day-ahead market. They are bids and offers that take financial positions without the intent of delivering or consuming actual power in the real-time market.
FERC last week rejected two complaints alleging that MISO overcharged for through-and-out transmission on the MISO South system.
The nearly identical complaints originated from Morgan Stanley Capital Group and eight Entergy export customers, including several Southern Co. utilities and the Springfield, Mo.-based Associated Electric Cooperative Inc. (AECI). The complainants claimed that the power they received from Entergy’s territory was overpriced, violating the grid operator’s no-cost-sharing rule and section 206 of the Federal Power Act. They sought refunds from Dec. 19, 2013, when Entergy transferred control of its transmission facilities to MISO. The parties also asked for an investigation if FERC found improprieties.
FERC found that the through-and-out transaction rates did not violate MISO’s Tariff because the no-cost-sharing-rule found in Tariff attachment FF-6 doesn’t apply to through-and-out charges (EL15-66, EL15-77). The commission also decided the complaints were “duplicative” because the justness and reasonableness of the rates under section 206 is already being challenged by AECI (EL14-19).
That case opposes current through-and-out transmission rates under recent MISO Tariff revisions that provide a five-year transition period “governing regional allocation of network upgrades.” MISO filed for the Tariff changes with FERC in mid-2013 after Entergy moved to MISO control.
“Commission precedent prohibits the filing of successive complaints that seek to re-litigate the same issue absent new evidence or changed circumstances,” FERC wrote.
The complaints said that since the MISO integration, the charges for long-term firm point-to-point transmission service have risen from an average of $1.78/kW-month to $3.45/kW-month.
In its complaint, Morgan Stanley said it was unjust for MISO to apply differing transmission rates to customers based on if they have a sink in or out of the RTO. The company said MISO’s cost assessments are discriminatory because MISO is excluding “MISO Midwest costs from transmission rates charged to former Entergy customers that have a sink in MISO South but is not excluding such costs from former Entergy customers that sink outside of MISO South.” The company also said that customers that sink in SPP are being treated differently than those that sink in PJM.
MISO said the complaints overlooked elimination of its pancaked rate as a result of Entergy’s integration.
“MISO and Entergy state that the purpose of applying an average system-wide rate to through-and-out service is to treat all competitors for a specific load the same. In MISO’s view, complainants are asking the commission to grant them a preferential rate not available to other similarly situated customers,” MISO stated.
FERC last week denied requests for changes to Order 807, which granted a blanket waiver from Open Access Transmission Tariff requirements to owners and operators of generator tie lines (RM14-11-001).
The commission denied a rehearing request from the National Rural Electric Cooperative Association (NRECA) and a second filed jointly by the American Public Power Association (APPA) and the Transmission Access Policy Study Group (TAPS).
Safe Harbor
NRECA asked the commission to reconsider its presumption that an ICIF owner has plans to use its capacity when the third-party requesting transmission service is a load-serving entity.
NRECA noted that renewable generating resources are often located in remote areas and require long tie lines to connect to the interstate grid. The group said it would be more efficient for an LSE to contract with an ICIF owner to counterflow power over the line rather than to build a new facility to serve its native load.
It said the tie line owner should have the burden of proving it has specific plans to use the excess capacity that would prevent it from providing LSEs access.
FERC said it disagreed with NRECA’s contention that the five-year safe harbor period “impinges upon the reasonable needs of LSEs.”
“Because of the case-specific nature of any request under sections 210 and 211 to use certain ICIF, we cannot … state exactly what evidence would be strong enough to overcome the rebuttable presumption during the safe harbor,” FERC added.
Open Access
FERC also rejected the allegation by APPA and TAPS that the rule grants tie line owners vertical market power over access to their facilities. The groups said FERC unfairly ruled that third parties would not be unduly burdened by pursuing transmission service under Federal Power Act sections 210 and 211.
The commission said its rule “does not foreclose access” to tie lines but sought to reduce unnecessary regulatory burdens for owners that may plan to use excess transmission capacity for future phases of generation construction.
“Without such reasonable assurance, there would be little incentive for a developer to shoulder the extra expense of ICIF sized larger than the initial phase of the project,” the commission said.
Clarification
The commission clarified that no commission proceeding is necessary for a blanket waiver to be revoked if the public utility acquires additional transmission facilities that are not ICIF or otherwise no longer qualifies for the exemption. FERC said the waiver would be automatically revoked and the owner would be required to file an OATT within 60 days.
FERC also clarified that non-public utility ICIF owners may also take advantage of the blanket waiver and safe harbor period.
“Although the determination in the final rule does not explicitly state that non-public utility ICIF owners may take advantage of the blanket waiver, this omission was unintentional,” the commission said. “The intent of the final rule was to make the package of reforms equally available to nonpublic utility ICIF owners.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
3. PJM Manuals (9:25-9:35)
Members will be asked to endorse the following manual change:
Manual 14B: PJM Region Transmission Planning Process. Establishes criteria for reliability studies focused on meeting winter peaks from Dec. 1 through Feb. 28. Includes assumptions for the input power flow models and parameters for the analytical studies to be performed. (See “Winter Study Criteria, Uplift Added to Planning Manual,” in PJM Planning Committee Briefs.)
4. TIER 1 COMPENSATION (9:35-9:55)
The committee will be asked to approve manual and Tariff language changing compensation of Tier 1 synchronized reserves. Under the new scheme, Tier 1 synchronized reserve resources will be obligated to respond in emergencies and subject to penalties if they can’t. It retains Tier 1’s ability to receive compensation outside of synch reserve events when the non-synch reserve market price is more than $0. Units could opt out of the performance obligation, but by doing so they would forfeit any credit they would have received outside of responding to an event. The changes will go before the MC on Nov. 19 and would be implemented no earlier than February. (See “Tier 1 Compensation Language Approved,” PJM Market Implementation Committee Briefs.)
5. REGULATION PERFORMANCE IMPACTS (9:55-10:10)
The committee will be asked to endorse revisions to Manual 11: Energy & Ancillary Services Markets Operations implementing changes to reduce over-procurement of RegD resources. The solution would move the benefits factor curve to the left so that it is at zero at 40%. A cap of 26.2% also would be implemented during identified excursion hours — hours when dispatch frequently moves the regulation signal manually. It also features tie-breaker logic to rank RegD self-schedules or zero-cost offers. (See “Solution, Task Force Proposed to Curtail RegD Resources,” in PJM Markets and Reliability Committee Briefs.)
6. REGULATION MARKET ISSUES SR. TASK FORCE (rmistf) (10:10-10:20)
Members will be asked to endorse a draft charter for the Regulation Market Issues Senior Task Force. The task force will be tasked with addressing modeling problems that are causing PJM’s regulation market to purchase too much RegD megawatts at times. (See agenda item 5 above.)
7. INCREMENTAL AUCTION TARIFF CLEAN UP (10:20-10:30)
A Tariff provision up for endorsement would allow PJM to release Base Capacity resources to reflect the Capacity Performance resources it acquired in the transition auctions for the 2016/17 and 2017/18 delivery years. (See “PJM Seeks Tariff Change to Release Excess Capacity,” in PJM Markets and Reliability Committee Briefs.)
8. 2015 IRM STUDY RESULTS (10:30-10:45)
The results of the 2015 installed reserve margin study will be presented for endorsement. It increases the IRM for delivery year 2016/17 to 16.4% from 15.5% in the 2014 study. IRMs also rose for 2017/18 and 2018/19. (See “IRM, FPR Rising; PJM Methodology Challenged,” PJM Planning Committee Briefs.)
9. GOVERNING DOCUMENTS ENHANCEMENT AND CLARIFICATION SUBCOMMITTEE (gdecs) (10:45-10:55)
The committee will be asked to approve a draft charter for the Governing Documents Enhancement and Clarification Subcommittee, which will be tasked with identifying, reviewing and resolving inconsistencies among PJM’s governing documents and manuals. It also will offer revisions to correct ambiguous or confusing language.
Members Committee
ENDORSEMENTS (1:25-2:00)
CONSUMER ADVOCATES OF PJM STATES (CAPS) (1:25-1:55)
Members will be asked to vote on a proposal to fund a $450,000 budget for the nonprofit Consumer Advocates for the PJM States through an assessment on electric customers. It would amount to about 0.8 cents annually for a residential customer using 12,000 kWh. (See Consumer Advocates’ Funding Request Sparks Sharp Words.)
ELECTIONS (1:55-2:00)
Members will be elected for the Nominating Committee for 2015-16. The sector representatives are:
Electric Distribution Sector: Lisa McAllister, American Municipal Power
End Use Customer Sector: Ruth Ann Price, Division of the Public Advocate of the State of Delaware
Generation Owner: Joe Kerecman, Calpine
Other Supplier Sector: Marji Philips, Direct Energy
Transmission Owner Sector: John Horstmann, Dayton Power & Light
