Page 1395 – RTO Insider

November 22, 2016

New FERC Rule Will Double RTO Offer Caps

By Robert Mullin

With winter looming, FERC last week adopted a rule that would double the “hard” offer cap for day-ahead and real-time markets to $2,000/MWh in every RTO and ISO.

Order 831 was a response to the 2013-2014 polar vortex, which caused natural gas price spikes that left some generators in the Northeast complaining they were unable to recover their costs (RM16-5).

The commission also noted that the $1,000/MWh offer caps effective in most RTOs could suppress LMPs below the marginal cost of production “given that recent history demonstrates that resource short-run marginal costs can exceed” that cap.

“We find that the currently effective offer caps may prevent a resource from recovering its short-run marginal costs, which could result in that resource operating at a loss,” the commission said in its decision to adopt the rule.

ferc rto offer caps — | © *mg154 / 123RF Stock Photo*

FERC last year approved a PJM measure to increase its offer cap to $2,000/MWh after RTO stakeholders voted overwhelmingly to approve the move. (See PJM Members OK 2,000/MWh Energy Market Offer Cap.)

The commission’s revised offer cap rule sets out three requirements:

Incremental energy offers must be capped at the higher of $1,000/MWh or a resource’s cost-based energy offer, with $2,000/MWh being the maximum bid.
An RTO must verify the costs underlying a resource’s bid above $1,000/MWh before that offer can be used to calculate the market-clearing LMP.
All resources — regardless of type — will be eligible to submit cost-based incremental energy offers in excess of $1,000/MWh.

The final rule modifies FERC staff’s original proposal, which would have converted the current $1,000/MWh cap into a “soft” cap — without implementing a new hard cap. (See FERC Proposes Uniform Offer Caps Across RTOs.)

The commission said the absence of a hard cap could be problematic for RTOs and their market monitors, who might have only “imperfect information” ahead of the market clearing process to verify the short-run marginal costs for resources bidding above $1,000/MWh.

“While a hard cap may diminish the ability to fully address the shortcomings of current offer caps identified above in all circumstances, we find that, on balance, a hard cap is necessary to reasonably limit the adverse impact that any imperfect information during the verification process could have on LMPs,” the commission said.

Opposing the rule was CAISO, which said that the current $1,000/MWh ceiling far exceeds the highest cost-justified offer from any ISO resource. CAISO further contended that any natural gas-driven price spikes would be too infrequent and short-lived to warrant a change. ISO-NE said it saw no need to increase the cap, but it didn’t contest the rule change.

Market monitors for ISO-NE and SPP also protested, arguing that new sources of gas supply have provided sufficient stability in fuel prices in recent years.

The commission dismissed those contentions, pointing out that three RTOs — PJM, MISO and NYISO — had made previous filings to temporarily waive or change the level of their offer caps.

“The waiver requests and high natural gas costs experienced during the polar vortex, which could have caused some resources to experience costs above $1,000/MWh, demonstrate that the deficiencies of current offer caps, in particular the $1,000/MWh offer cap, are concrete rather than hypothetical.”

In its Nov. 17 presentation to the commission explaining the rule, FERC staff made the case for applying the change to all organized markets.

“Adopting the same offer cap structure in each RTO and ISO would avoid seams issues that could arise if offer caps differ materially across markets,” staff said.

The new rule will be effective 75 days after publication in the Federal Register.

November 22, 2016

Appeals Court Ruling for Bondholders Clouds EFH Reorganization

By Tom Kleckner

A U.S. appeals court last week ruled Energy Future Holdings must pay hundreds of millions of dollars to certain bondholders, adding a cloud of uncertainty to the bankrupt company’s attempts to emerge from Chapter 11 protection.

Lamar Plant | Luminant - energy future holdings bankruptcy — Lamar Plant | *Luminant*

On Thursday, the 3^rd Circuit Court of Appeals in Philadelphia reversed lower court decisions and directed EFH to pay holders of the company’s first-lien and second-lien notes. The bondholders had argued that by repaying its debt early in the bankruptcy proceeding, EFH owed them prepayment premiums — or make-whole payments — of $431 million and $351 million, respectively. The payments don’t include several years of interest.

The decision affects $6.2 billion in debts that were refinanced after EFH declared bankruptcy in 2014. The company has said that disallowing the make-whole claims is a condition of its reorganization and that the added litigation would reduce the funds available to other creditors.

The U.S. Bankruptcy Court in Delaware, which has jurisdiction over the case, is to begin hearings to consider confirming the Texas company’s reorganization Dec. 1.

EFH’s reorganization plan hinges partly on the sale of its Oncor wires business to Florida-based NextEra Energy for $18.4 billion. NextEra and Oncor filed for approval of the sale with the Public Utility Commission of Texas on Oct. 31. (See NextEra Energy Talks Up its Oncor Acquisition.)

It’s unclear whether the additional debt would affect NextEra’s acquisition of Oncor, which relies on eliminating debt and replacing it with equity.

EFH has already spun off its Luminant and TXU Energy businesses into a standalone company, since rebranded as Vistra Energy. (See Luminant, TXU Energy Emerge from Bankruptcy.)

Vistra Energy and NextEra both declined requests for comment by RTO Insider on the court’s ruling and its potential effect on the Oncor acquisition.

Meanwhile, NextEra and Oncor are plunging ahead with their merger application in Texas.

Friday, the state’s Public Utility Commission filed an order finding their application to be sufficient (Docket 46238) and an administrative law judge affirmed hearings before the PUC will begin Feb. 21.

The ALJ also granted all motions to intervene in the case. Those intervening include the Texas Office of Public Utility Counsel, NRG Texas, TXU Energy, Local 69 of the International Brotherhood of Electrical Workers, Texas Industrial Energy Consumers and a group of cities currently served by Oncor.

PUC staff has requested Oncor address a set of questions focused on the utility’s rating agency reports, its five-year capital plan and the tax status of the EFH spin-off.

November 22, 2016

FERC Rejects Entergy Attempt to End PPA with Goodyear Plant

By Tom Kleckner

FERC last week rejected Entergy Texas’ attempt to terminate a power purchase agreement with qualifying facilities at Goodyear Tire & Rubber’s Beaumont chemical plant (EL16-105).

Goodyear filed a complaint with the commission in August, alleging that Entergy Texas’ plan to terminate its PPA with the tire company’s QFs in Southeast Texas violated the utility’s obligation to purchase energy and capacity in accordance with the Public Utility Regulatory Policies Act of 1978.

Goodyear's Beaumont Chemical Plant | Goodyear - Entergy power purchase agreement — Goodyear’s Beaumont Chemical Plant | *Goodyear*

Entergy contended it had the right to cancel the PPA based on FERC’s January order that terminated the utility’s obligation to purchase from QFs larger than 20 MW in MISO. (See FERC: Entergy not Required to Buy from Large QFs.)

Goodyear’s Beaumont/West QF was self-certified in 1987 with a net capacity of 13 MW. Its Beaumont/East QF was self-certified in 1999 with a net capacity of 18.8 MW.

Entergy argued that the two QFs should be considered as one. It noted that the QFs are located less than a half-mile apart on the same site and that their energy “is commingled behind the meter.”

Goodyear contended that because it had self-certified two cogeneration plants each smaller than 20 MW, the January order did not affect Entergy’s obligation.

The commission agreed. It said its January order concluded that “a QF’s size for purposes of being relieved of the mandatory purchase obligation is determined by its certified size.”

The commission’s January order was based on a 2006 ruling, which said that QFs with net capacity above 20 MW were presumed to have “nondiscriminatory access” to wholesale markets in RTOs such as MISO.

November 22, 2016

MISO, PJM Move Forward on TMEPs; 6 Projects Planned

By Amanda Durish Cook

CARMEL, Ind. — MISO and PJM are close to implementing a targeted market efficiency project (TMEP) type and poised to approve six such projects with cross-regional benefits.

Moser | © RTO Insider - miso pjm tmep — Moser | © *RTO Insider*

During the Nov. 15 MISO and PJM Joint and Common Market meeting, Jesse Moser, MISO manager of infrastructure studies, said the RTOs must make a FERC filing to change their joint operating agreement in addition to individual filings on how they plan to handle cost allocation.

Moser said the RTOs prefer making the necessary three filings simultaneously, but they would file standalone JOA changes before the end of the year if certain regional cost allocation details are not finalized in time.

“We’re happy to see this move forward,” Moser said.

The two RTO’s staff say the final six projects are expected to cost about $17.25 million and deliver $111.6 million in reduced congestion on market-to-market flowgates, an average 6.5:1 benefit-to-cost ratio.

The RTOs examined 50 market-to-market flowgates and produced the final six from a pool of 13 potential upgrades. The final six exclude the previously recommended Klondike-Purdue 138-kV project in north-central Indiana, which did not advance because of the discovery that the congestion the project was designed to relieve was outage-driven. (See 7 Sites Eyed for MISO-PJM Targeted Market Efficiency Projects.) “These are meant to be lower cost projects … that have near-term economic benefits,” Moser explained.

MISO to Seek Bifurcated Cost Allocation

Solomon | © RTO Insider — Solomon | © *RTO Insider*

At a Nov. 17 conference call of MISO’s Regional Expansion Criteria and Benefits Working Group, transmission engineer Adam Solomon said the RTO will pursue a bifurcated cost allocation for the TMEPs. MISO proposes to assign cost to a local transmission pricing zone when the constraint is on the transmission of one or more transmission owners. For constraints wholly within PJM, MISO is seeking a postage stamp allocation for all of the MISO North region.

Solomon said MISO decided on a postage stamp for projects within PJM because all local transmission pricing zones would gain from lowered congestion.

PJM officials did not discuss their cost allocation plans at the meeting. Spokeswoman Paula DuPont said the regional cost allocation is being developed by PJM’s Transmission Owners Agreement-Administrative Committee.

The two-option proposal would apply to both RTO’s current batch of TMEPs. “We’re certainly open to looking at it in the future if we can get a better cost allocation,” Solomon said.

Shelly-Ann Maye, representing Midwest Power Transmission Arkansas, said she didn’t understand why a postage stamp allocation could be justified when local beneficiaries in MISO could be identified.

“These projects are avoiding future congestion in MISO, and that congestion gets pretty well spread out in the footprint,” Solomon explained.

Of the six TMEPs currently being considered, the Marysville-Tangy 345-kV project in central Ohio is the only project that would qualify for the postage stamp allocation, as it is located wholly within PJM, Solomon said.

Solomon also said the cost allocation rules will only apply to the PJM-MISO seam. MISO staff said they plan to collect more SPP day-ahead market-to-market information and expect to begin discussions with SPP on a similar project type.

“Having this cost allocation spelled out in the JOA and Tariff, I think, will help these projects go through and we can get the benefit of those projects we’re forecasting,” Solomon said.

Wisconsin Public Service’s Chris Plante said his utility was hoping for 50% local pricing zone allocation and 50% postage stamp allocation for all TMEPs.

“We think this is the best proposal that we have at this point with stakeholder feedback considered,” Solomon said.

Retirement Coordination

Neil Shah, MISO adviser of seams administration, also said that both RTOs are planning to file a generator retirement coordination process with FERC by Dec. 15. Shah said the final language was largely unchanged from what was proposed last month. (See MISO Outlines Retirement Coordination with PJM.)

November 22, 2016

Sandoval: Nuke Shutdown, Auto-DR Aided Aliso Canyon Response

By Robert Mullin

LA QUINTA, Calif. — While the loss of the San Onofre nuclear plant complicated California’s response to the closure of the Aliso Canyon natural gas storage facility last year, planners did benefit from actions taken in the wake of the plant’s 2013 shuttering, according to California Public Utilities Commissioner Catherine Sandoval.

aliso canyon auto-dr — Sandoval | © *RTO Insider*

“All of that work helped us to better withstand Aliso Canyon when the number one source of natural gas was no longer available,” Sandoval told an audience at the National Association of Regulatory Utility Commissioners’ 128th Annual Meeting.

In response to the shutdown of San Onofre — the largest generator in the state’s most populous area — officials ordered transmission upgrades, installation of synchronous condensers to facilitate the flow of electricity into the Los Angeles area and “a variety of things to help keep the system up and running electrically,” Sandoval said.

The loss of Aliso Canyon prompted the CPUC to authorize additional measures to shore up the region’s grid, including accelerated deployment of energy storage and expedited interconnection procedures. The state also stepped up implementation of demand response to shave summer electricity — and, by extension, natural gas — demand.

“This isn’t your father’s demand response; this is auto-DR,” Sandoval said. Among the most successful auto-DR programs: air-conditioner cycling, which allowed utility customers to select from a range of potential curtailments of their cooling units during periods of high electricity demand.

Aliso Canyon | California Governor's Office of Emergency Services — Aliso Canyon | *California Governor’s Office of Emergency Services*

The program yielded 300 MW in DR, Sandoval said. “That’s a peaker plant. So we were able to get a negawatt peaker through auto-DR,” Sandoval said.

Southern California weathered the summer without incident on either the gas or electricity system. Now planners are turning their attention to winter, when heating requirements create a second peak for gas demand not driven by electricity generation. (See CAISO Seeks to Extend Aliso Canyon Gas Rules Through Winter.)

While Aliso Canyon owner Southern California Gas has been testing the storage facility for leaks, the CPUC still hasn’t authorized reopening. No set timetable has been established for bringing the facility back online.

“We really have to come up with new messages [for consumers] that are actually well-tailored to the winter side,” Sandoval said. “We have to think about what sorts of programs can we adopt to really ensure that there’s gas sufficiency so that we don’t run into problems, especially if we’re not able to bring Aliso back online.”

November 22, 2016

PJM, NYISO Still Seeking Spot-in Tx Solution

By Rory D. Sweeney

NYISO and PJM are finding that coordinating transmission across their border is not simple.

After an effort to make it easier for traders to schedule imports from New York failed at the Nov. 2 Market Implementation Committee meeting, stakeholders will resume efforts at a special MIC meeting Dec. 21.

Vitol’s Joe Wadsworth, who has championed efforts to streamline the process for several years, won stakeholder approval in April for a problem statement seeking ways to improve the method of reserving PJM spot-in (non-firm) transmission for energy imports scheduled day-ahead from NYISO. Spot-in service is free but limited and allocated on a first-come, first-served basis.

Additionally, the deadlines for requesting the service from PJM and learning the results of NYISO’s day-ahead energy auction are staggered such that participants looking to import power must reserve spot-in capacity from PJM before knowing how much they’ll need. PJM requests must be made at 9 a.m. to have any hope of success, yet the results of NYISO’s day-ahead market usually aren’t available until after 9:30 a.m.

spot-in solution pjm nyiso — | *Josef Kubes / 123RF Stock Photo*

This creates the risk that “there may not be enough spot-in service available for participants who received a cleared day-ahead schedule to import power into PJM,” the problem statement reads, which leaves them “scrambling” to find service. Failure to obtain transmission results in the import being curtailed, which “can create imbalances that must be settled against real-time prices.”

Armed with the problem statement, Wadsworth, PJM and NYISO began discussing potential solutions. NYISO, concerned about those potential imbalances creating costs for its members, proposed a market-based solution that would allocate the costs to PJM’s members.

Wadsworth also favored a market-based solution, but PJM decided, after researching potential solutions, that it would be a much more difficult implementation than the RTO preferred. As a compromise, Wadsworth and PJM developed a proposal that they thought addressed the problem without being overly complex: delay the earliest request for spot-in service from 9 a.m. to 10 a.m. so participants will know how much they need before they request it.

Wadsworth and PJM’s Chris Pacella presented the idea at the Nov. 2 MIC meeting.

“Maybe this is the simple change that eliminates all those risks,” Wadsworth said. (See “NYISO to be Consulted on Changing Spot-in Service Allocation Methods,” PJM Market Implementation Committee Briefs.)

Problem solved!

Software Changes

Except there was one catch: Pacella explained that PJM can make a deadline change for all imports, but that limiting the change to just NYISO would require time-consuming software changes.

PJM Independent Market Monitor Joe Bowring took issue with making a global change, saying it’s not consistent with the problem statement. When the issue first came up, he said, he attempted to argue that it should apply to all RTO interfaces, not just NYISO, but was “told explicitly” that was out of the problem statement’s scope. He said the correct procedural step would be to amend the problem statement to include all RTO seams.

Dan Griffiths, of the Consumer Advocates of the PJM States, agreed. “I’m kind of indifferent to the outcome, but I’d like to see this addressed properly,” he said.

PJM’s Mike Bryson cautioned against the global approach, saying it would create operational problems. “The all-borders issue causes me great concern,” he said.

Wadsworth agreed, saying he preferred to limit the scope of the deadline change to just the NYISO seam. “I think we need to think through all the consequences,” he said.

Other stakeholders, however, wanted to get to the bottom of NYISO’s concerns. “I’d like a better explanation of the mechanics of what it is that NYISO thinks is increasing the costs,” said Roy Shanker of H.Q. Energy Services. “This summary just doesn’t make sense to me. … You may or may not want to pick a fight, but I feel like everybody on both sides should know what’s going on.”

“In these preliminary stages, we’re beholden to New York’s stance,” Pacella said. He later acknowledged, however, that there is precedent for a market-based solution with the cross-seam transmission agreement in place between NYISO and ISO-NE.

An MIC vote on amending the problem statement, which was motioned by Bob O’Connell of PPGI Fund A/B Development and seconded by Jung Suh of Noble Americas, was tabled until the committee’s next meeting on Dec. 14. However, it likely won’t receive much discussion there because of the MIC special session on Dec. 21. It is scheduled from 1 to 3 p.m. at PJM’s Conference & Training Center in Valley Forge.

November 22, 2016

Minn. City Granted FERC Standards of Conduct Waiver

FERC last week granted Rochester, Minn., a waiver of its Standards of Conduct, finding that the city qualifies as a small public utility.

The commission’s Nov. 17 ruling said the waiver will remain in effect “unless and until the commission takes action on a complaint by an entity that Rochester has unfairly used its access to information to unfairly benefit itself or its affiliates” (TS15-3).

ferc standards of conduct waiver — Zumbro Hydro Dam | *Rochester Public Utilities*

The southeastern Minnesota city sought the waiver in September 2015, claiming it met the definition of a non-jurisdictional utility. Jurisdictional transmission providers are subject to the Standards of Conduct, which require transmission function and marketing function employees to operate independently of each other and prohibit sharing nonpublic transmission information with marketing employees.

Without a waiver, Rochester said it would indirectly be subjected to the standards based on the commission’s reciprocity rules, which ensure nonpublic utilities’ access to transmission service from public utilities. The city pointed out it transferred operational control of its transmission to MISO in late 2014; the waiver requires that utilities own, operate or control “only limited and discrete transmission facilities.”

Rochester’s municipal utility serves about 50,000 customers, mostly with power purchased from the Southern Minnesota Municipal Power Agency. It owns and operates about 86 MW of generation, 42 miles of transmission and 793 miles of distribution. Early this year, Rochester officials announced that the public utility would begin building a new 47-MW natural gas plant in 2017. The utility has proposed a 3.7% rate increase in 2017.

— Amanda Durish Cook

November 22, 2016

BGE Reaches Settlement with MISO Members in Congestion Dispute

Baltimore Gas and Electric will pay $170,530 to MISO members to end a dispute over cross-system congestion costs under a settlement approved by FERC last week.

FERC’s Nov. 17 order settles a dispute between BGE and almost 30 MISO utilities relating to the cross-system congestion costs known as Seams Elimination Charge/Cost Adjustments/Assignments (SECA). FERC said the uncontested agreement represents “a final settlement of all SECA obligations.”

| Baltimore Gas & Electric — | *Baltimore Gas & Electric*

The settlement directs BGE to pay members of the RTO $344,665 and for the RTO to collect $174,135 from its members for BGE, for a net payment by BGE of $170,530. The approval closes out dockets ER05-6-124, EL04-135-126, EL02-111-145 and EL03-212-140.

The SECA cases originated from a 2002 FERC decision allowing American Electric Power, Commonwealth Edison and Dayton Power and Light to move from MISO to PJM. The move created areas in the RTO that were cut off from the rest of the footprint and led to rate pancaking and the eventual elimination of regional through-and-out rates.

FERC approved the 16-month SECA transitional payment mechanism for 2004-2006 and upheld SECA use in 2010, but it said SECA rates recovered from MISO and PJM transmission customers were subject to refund by MISO and PJM transmission owners. The 2010 decision imposed additional SECA liabilities on BGE. MISO laid out SECA amounts in 2013, charging BGE and about 15 other PJM load-serving entities a combined $4 million in SECA charges.

— Amanda Durish Cook

November 22, 2016

SPP Gathers Technology Vendors to Share Wares

By Tom Kleckner

LITTLE ROCK, Ark. — SPP gathered a half-dozen vendors to show off some of the latest transmission technologies before an audience of stakeholders and staff last week. A first for SPP, the Technology Expo was following a trend set by other RTOs.

Ryan | © RTO Insider — Ryan | © *RTO Insider*

“Doing these things is necessary because technology is evolving,” said Todd Ryan, director of regulatory affairs for Smart Wires. “It’s good for us because it helps us understand where our product fits in.”

Ryan was on hand to push his company’s PowerLine Guardian, a modular transmission power-flow control that the company says “will change how power grids are designed and operated.” Combined with the company’s Power Router, the Guardian addresses congestion through local control or central dispatch through devices hung on conductors and towers or deployed in substations.

“You ever hear of the Whac-a-Mole problem?” Ryan asked. “When you solve a problem in one place, it just to moves to another. Every grid has this problem, but [with Smart Wires], you have a tool to more finely tune your investment to your needs and whack more moles.”

Other speakers shared the latest on advanced conductors, topology optimization, dynamic line rating, energy storage and HVDC transmission lines. Almost three dozen members of SPP’s staff and stakeholders attended the expo, with others listening on the phone.

“All technologies are about two things: bringing new capacity to the market and integrating renewables,” said Joe Coffey of General Cable. He motioned to the screen behind him, where a slide showed higher-capacity conductors. “Hey look, a new technology!”

spp technology exp — Doug Bowman (center) shares a laugh with the Technology Expo’s speakers | © *RTO Insider*

Jay Caspary, SPP’s director of research, development and Tariff studies, said the expo was designed to educate staff and stakeholders “of opportunities that exist today to improve grid operations and planning.”

“We look forward to continued dialogue with interested stakeholders, and we will work with members on efforts which could lead to pilot programs in the near future,” Caspary said.

November 22, 2016

FERC Considers Change to Hydro License Rules

By Rich Heidorn Jr.

FERC said last week it is considering changing the way it establishes license terms at nonfederal hydropower projects.

hydropower license rules meldahl project — | *FERC*

The Federal Power Act allows the commission to issue original licenses for up to 50 years and renewals for between 30 and 50 years.

The commission’s current policy on renewals is to set a 30-year term when there is little or no new construction, or environmental mitigation required; a 40-year term for projects with a “moderate” amount of such activities; and a 50-year term for projects requiring “an extensive” amount of such activity.

“The purpose of this policy is to ease the economic impact of new costs and promote balanced and comprehensive development,” FERC staffer Carolyn Clarkin said in a presentation at Thursday’s open meeting. “Determining whether the measures required under a license are minimal, moderate or extensive is highly case-sensitive and largely based on a qualitative analysis of the record before the commission.”

The commission’s policy is a forward-looking approach, “such that measures adopted under a previous license term are not considered,” Clarkin added.

In a draft Notice of Inquiry (RM17-4), FERC sought comment on five potential options:

Retaining the existing license-term policy
Considering measures implemented during a prior license term
Establishing a 50-year default license term
Including a “more quantitative cost-based analysis”; and
Establishing the license term based on negotiated settlement agreements when appropriate.

The open meeting also featured a staff presentation on the commission’s dam safety program and a description of the recently opened Meldahl Project, four sets of hydropower turbines at locks and dams on the Ohio River. A joint venture between American Municipal Power and the City of Hamilton, Ohio, the 300 MW project was the first major hydropower project constructed in several decades in the U.S.

FERC regulates more than 2,500 dams with 55,800 MW of capacity, more than half of all hydroelectric capacity in the U.S. Almost 1,000 of the dams are classified as posing high or significant hazards and subject to annual inspections. The remaining, low-hazard, dams are inspected every three years.