Page 1324 – RTO Insider

April 24, 2017

MISO Planning Advisory Committee Briefs

CARMEL, Ind. — MISO is planning to eliminate temporary suspensions of generating resources, a move the RTO says will provide resource owners more flexibility.

The existing Attachment Y suspension status requires that owners supply MISO with a return date. Under the new rules, the status would be reduced to a binary option: on or off.

MISO attachment Y — Reddoch | © *RTO Insider*

Fewer options actually translate into greater flexibility for resource owners, MISO adviser Joe Reddoch told stakeholders at the April 19 Planning Advisory Committee meeting. He said generation owners will now be able to enter a catch-all “economic shutdown” period using an Attachment Y, giving them time to evaluate options over a planning year before rendering a final decision to retire.

The decision point will align with the Planning Resource Auction, with interconnection service intact for a full planning year after a notice to go offline is submitted. If approved by FERC, the new process will be added to MISO’s Tariff.

The same planning yearlong rescission period will apply to system support resources whose status has been lifted by MISO.

“Once a generator submits an Attachment Y retirement notice, they cannot change their minds. If they do, they have to re-enter the interconnection queue,” Reddoch said of MISO’s current process.

Reddoch added that MISO’s current six-month suspension timeline is “a bit cumbersome” with multiple filing deadlines. He also said that suspension notices can sometimes “mask” lost megawatts because MISO assumes suspended resources will eventually come back online.

The changes stem from the Independent Market Monitor’s 2013 State of Market Report recommendation that MISO improve alignment between its Attachment Y process and the PRA timeline. The Monitor said that an Attachment Y unit that participates and clears in the PRA should be allowed to “defer the effective date of retirement.” (See “Aligning Attachment Y Process with PRA,” MISO South-to-Midwest Transfer Limit Upped for 2017/18 PRA.)

Once an Attachment Y request is submitted, MISO will carry out an Attachment Y retirement reliability study as usual, but with one added feature: Upon completion of the study, MISO will publicly post study results. Some stakeholders expressed concern at the heightened transparency.

Indianapolis Power and Light’s Lin Franks said publicly posting the results might inadvertently create a panic in some companies that have not publicly announced plans to retire.

“You may understand that you’re trying to take a middle ground, but the guy at the plant [losing his job] doesn’t understand that,” Franks said.

“That’s fair enough,” Reddoch replied.

Other stakeholders asked MISO to consider deferring public results of Attachment Y until the new decision point deadline, but Reddoch said early warning is key when planning for retirements.

“When you keep things confidential, it’s hard to talk about upgrades or projects that are needed when we can’t talk about why those projects might be needed,” Reddoch said. “If you don’t start on upgrades early enough, and a plant does retire, you might have reliability issues. Our thinking is you want to get started early on the timeline if these things require a number of years to complete.”

WPPI Energy’s Steve Leovy suggested that Franks’ company could initiate MISO’s optional nonbinding Attachment Y study. Franks said IPL had gone through the “horrible” process and does not want to repeat it. “Okay, that sounds like another issue,” Leovy said.

The Environmental Law & Policy Center’s Justin Vickers said his firm supported MISO’s stepped-up transparency, saying that posting study results would assist in preparations and be “good for the footprint.”

MISO will take stakeholder feedback on proposed Tariff changes through May 10.

48 Competitive Tx Contenders in 2017/18

MISO is reviewing qualifications of 48 transmission developers that submitted documentation to become or renew their status as competitive developers for this year’s planning cycle, the same number as last year. The exercise is likely to be moot, however, as MISO is not expected to announce a competitive project this year.

— Amanda Durish Cook

April 24, 2017

NYISO, PJM Discuss PARs’ Benefits, Cost Allocation

By Michael Kuser

RENSSELAER, N.Y. — Lots has changed since 1993, when members of the New York Power Pool and several transmission owners in PJM agreed to split the cost on two phase angle regulators (PARs) at Consolidated Edison’s Ramapo substation.

PJM NYISO cost allocation pars — ConEd PAR | *ConEd*

The power pool was succeeded by NYISO, PJM grew west to Chicago and FERC issued Order 1000, which set new cost allocation rules.

Those changes are now complicating efforts by the ISO and PJM to come up with a new cost-sharing agreement for the PARs, which control flows on the 500-kV Branchburg-Ramapo 5018 transmission line between New York and PJM.

On Tuesday, staff and stakeholders from both grid operators met at NYISO’s headquarters for a nearly daylong meeting to discuss ways to evaluate the value of the PARs and who should pay for them. The grid operators said they were pleased with the discussion and will meet again at PJM headquarters May 24 to continue talks.

And Then There was One

The need for better interface management originated in the great Northeast blackout of November 1965, which left 30 million people without power. Con Ed installed two PARs at Ramapo in 1988 and only five years later did the New York grid operator and PJM agree to split the entire costs 50/50 — purchase, installation and operation.

The original PARs both had a life expectancy of 40 years, but one was replaced after failing in 2013. The second original unit was destroyed in a substation fire last June. (See PAR Wars: A Struggle for Power.)

Con Ed is willing to purchase the replacement PAR but wants to be assured of repayment. Both sides estimate that it costs about $200,000 per month to run the two PARs.

Two-Track Approach by NYISO

“It all keeps coming back to the criteria” for determining benefits, Wes Yeomans, the ISO’s vice president for operations, said at the discussion April 18.

NYISO is taking a two-track approach: It is preparing to file a proposed Tariff revision with FERC to allocate the costs among all its load-serving entities and, at the same time, discussing with PJM how to share the costs.

The plan would promise to reimburse New York LSEs found to have overpaid their shares when the interregional cost allocation issues are resolved.

“Delay in reaching agreement on interregional cost allocation should not be permitted to indefinitely delay the installation of a second PAR at Ramapo,” the ISO said.

PJM says, however, that “cost allocation will only apply to transmission facilities that are approved in writing by all parties in advance of installation.”

Brian Wilkie, counsel for the New York Power Authority, suggested that “this discussion might be easier if PJM adopted NYISO’s practice of applying costs across all LSEs.”

Stan Williams, PJM director of performance compliance and market settlements, said, “I agree, but a lot of this is holdover from the 1993 JOA, which predates a lot of us, which is part and parcel of why we’re here.”

The 1993 Ramapo PAR agreement allocated 50% of the costs to the NYPP and 50% to the PJM group — which included only TOs in PJM’s Mid-Atlantic control zone.

Measuring the PARs’ Benefits

Any cost-sharing arrangement between NYISO and PJM will have to abide by FERC Order 1000’s guiding principle that transmission upgrades be “allocated in a way that is roughly commensurate with benefits.”

PJM and NYISO have yet to determine what reliability and economic criteria to use in their analysis. For example, are the effects on production costs more important than implications for reliability?

NYISO evaluates transmission upgrades under three separate planning processes: reliability, public policy and economic.

The ISO says the PARs provide reliability benefits during extreme contingencies or restoration following outages.

They also have market efficiency benefits: Without the PARs, NYISO’s ability to import lower-cost power from PJM is reduced. Those imports also have allowed the ISO to operate with smaller installed reserve margins and locational capacity requirements.

The ISO can import 1,700 MW from PJM in summer with both PARs and 1,400 MW with one. With neither PAR, the summer import limit drops to 1,000 MW.

Yeomans estimated the installed capacity benefits are about $75 million but would not elaborate on how he got that number, saying it came from two separate analyses, both made under non-disclosure agreements with third parties.

PJM’s list of suggested planning criteria included the impact of a second Ramapo PAR on revenue for holders of financial transmission rights — called “transmission congestion contracts” in NYISO. But Jane Quin, director of energy policy and regulatory affairs for Con Ed, objected to including such revenues as evaluation criteria, saying “that’s not how we treat” other similar facilities in NYISO.

DFAX Methodology

She also said Con Ed would opposed use of the distribution factor (DFAX) cost allocation method, as proposed by Public Service Enterprise Group, for evaluating benefits provided by the PAR.

Con Ed’s complaint over its $91 million bill for PSEG’s Bergen-Linden Corridor upgrade in North Jersey was one of the factors that led the utility to cancel use of the Con Ed-PSEG wheel.

The DFAX method also has been a flashpoint on the Artificial Island stability project in South Jersey. PJM has said that DFAX works well in many cases but can result in anomalous allocations. (See Board Restarts Artificial Island Tx Project; Seeks Cost Allocation Fix.)

Stan Williams, PJM director of compliance and settlements, said that “the PJM-MISO interface is a lot more complicated than [PJM-NYISO], with lots of nodes and contact points, whereas the major part in the NYISO interface is in the extreme Northeast, around New York City.” He added that the Ramapo PARs also play a wider role in the region, for example, contributing significantly to mitigating Lake Erie loop flows on the Michigan/Ontario interface.

PJM’s Chuck Liebold said that while PJM had reached no conclusions, when jointly planning the two grid operators normally look to the Northeast Protocol — the three-party agreement of NYISO, PJM and ISO-NE. Liebold suggested two options: They could establish a new type of interregional transmission project under the Northeast Protocol, or establish new planning provisions under their joint operating agreement.

Howard Fromer, director of market policy at PSEG Power New York, said, “If we’re devoting more money to this issue with the people in the room now than the cost of the project, we should develop a process applicable to many issues.” He added that the quantifiable benefits should include effects on emissions.

Timeline

New York’s timeline calls for May votes in the Business Issues and Management Committees on the changes, June approval by the NYISO Board, FERC filing immediately thereafter and Con Ed installing the second PAR in Fall 2017. The group hopes to have a proposal for PJM Markets and Reliability Committee to review in July.

Officials asked stakeholders to provide written comments to PJM and NYISO on the options by May 12.

April 24, 2017

Avangrid Renewables CEO Steps Down to Take NW Natural Role

By Robert Mullin

PORTLAND — Avangrid Renewables CEO Frank Burkhartsmeyer is resigning to take over as chief financial officer for Oregon-based natural gas service provider NW Natural.

Laura Beane, currently vice president of operations and management services at the renewables company, will take over the top spot once Burkhartsmeyer departs May 17.

In an internal memo to company employees, Avangrid CEO Jim Torgerson expressed “regret” over Burkhartsmeyer’s departure from the renewable energy company. Headquartered in Portland, Avangrid Renewables is a division of Connecticut-based Avangrid, the North American subsidiary of Spanish energy giant Iberdrola.

“Avangrid Renewables has grown under his leadership as CEO since 2015,” Torgerson said. Burkhartsmeyer, who has been with Avangrid and its previous affiliates for 20 years, was promoted to CEO after serving as the company’s senior vice president of finance. At NW Natural, Burkhartsmeyer will oversee the $3.1 billion company’s treasury, accounting, financial reporting, budgeting and forecasting, financial analysis, investor relations, business development, and supply chain activities.

“We are thrilled to have someone with Frank’s impressive experience on our officer team,” NW Natural CEO David Anderson said in a statement.

Beane joined Avangrid Renewables in 2007 after the company acquired PPM from Scottish Power. She had worked for 10 years at PPM under its previous parent, PacifiCorp.

“We are delighted to add Laura’s breadth of experience, knowledge and enthusiasm to the Avangrid Management Committee,” Torgerson said.

Avangrid Renewables has more than $10 billion in operating assets, representing more than 6,000 MW of capacity in 20 U.S. states.

April 21, 2017

Westar Shares Fall as Kansas Regulators Block Great Plains Deal

By Rich Heidorn Jr. and Amanda Durish Cook

Shares of Westar Energy fell 8% Thursday after Kansas regulators rejected as too risky and too expensive the company’s planned sale to Great Plains Energy.

The Kansas Corporation Commission voted 3-0 to reject the $12.2 billion deal, announcing it at the end of the day Wednesday.

Westar shares, which had ended Wednesday at $55.11, dropped $4.24 to $50.87 Thursday. Shares of Great Plains, the parent company of Kansas City Power and Light, were virtually unchanged, rising 4 cents to $29.55.

Price Too High

“The commission is not opposed to mergers as evidenced by its approval of two acquisitions within the past six months,” the commission’s order said. “As one of the intervenors notes, in many ways a merger between GPE and Westar makes sense, but for one insurmountable obstacle — the purchase price is simply too high.”

The commission said that based on their complementary service territories, a merger of the two companies could make sense. But it said the price was excessive and would force Great Plains to take on too much debt, noting the $4.9 billion acquisition premium exceeds Great Plains’ market capitalization by $100 million.

The commission also said that Great Plains’ winning bid of $60/share was $4 higher than that of the next highest offer. “Evidence suggests the $60/share purchase price exceeded the expectations of both Goldman Sachs and Guggenheim,” who validated the purchase price for Great Plains and Westar, respectively. Great Plains’ own analysis showed a “mid-fifties price point as the high end of a reasonable purchase price,” the commission said.

“Unfortunately, the transaction was presented to the commission as a take-it-or-leave-it proposal. Repeatedly, the joint applicants advised the commission that any significant safeguards that would protect consumers, such as maintaining a separate, independent Westar board of directors, would halt the transaction. Therefore, the proposed transaction could not be salvaged and the commission is left with no choice but to reject” it, the commission said.

The deal, announced last May, would have given Great Plains 1.5 million customers in a service territory covering the eastern one-third of Kansas, much of the Kansas City metropolitan area and a large portion of northwest Missouri. Great Plains said the merger would have increased its operating scale, resulting in efficiencies that would benefit ratepayers. (See Great Plains Asks Missouri PSC’s OK on Westar Deal.)

Debt Burden

Great Plains would have assumed $3.6 billion of Westar’s debt. It planned to finance the $8.6 billion purchase of outstanding Westar common stock with a package of 50% equity and 50% debt, including $4.4 billion in new debt. The company issued $4.3 billion in debt financing in March, the order noted.

“Since GPE has already completed both the equity and debt portions of the financing, it argues its ability to accomplish the financial steps necessary to close and support the transaction is no longer a concern. But the issue facing the commission in evaluating the transaction … is not whether GPE could obtain financing, but whether post-transaction, the resulting entity would be financially stronger than the stand-alone entities would be absent the transaction.”

The commission noted that Great Plains acknowledged that it expected Moody’s to downgrade its senior unsecured debt rating from Baa2 to Baa3, the lowest investment grade credit rating.

The commission cited the testimony of Great Plains CFO Kevin Bryant, who said that the company hopes to pay off $300 million to $500 million of debt within three to five years, but that it has no written plan to do so.

“Since GPE has failed to formulate any written plan to pay down the debt, the commission has nothing to review and cannot assume GPE will be able to rapidly deleverage. Therefore, the commission must review the joint application under the assumption that a post-transaction GPE will have substantial debt that will likely result in downgrades to its credit rating.

“The commission shares the concerns voiced by [the Kansas Board of Public Utilities] and [the Citizens’ Utility Ratepayer Board] that if the transaction is approved, GPE has little financial flexibility and very little margin of error to keep its investment grade rating. … The evidence is overwhelming that the rating agencies believe … GPE will be a riskier investment if the transaction goes through.”

The commission also noted Great Plains and Westar’s claims that applying a consolidated capital structure that included Great Plains’ transaction-related debt would halt the merger, saying such assertions were “a tacit admission that the joint applicants’ ability to complete the deal is entirely dependent on its ability to use the operating utilities’ higher rates of return to finance the transaction.”

Savings in Question

The commission also cast doubt on Great Plains and Westar’s estimated savings from the early retirement of five KCP&L generating units and five Westar units, calling them “too speculative to be reliable.”

Great Plains and Westar “support their application with little more than preliminary estimates, developed in only three weeks and without full access to Westar’s books or personnel,” the commission said of Great Plains’ savings analysis.

The commission also said Great Plains and Westar’s commitment to not seek recovery of the acquisition premium from ratepayers was flimsy at best. It pointed out that an exception to acquisition financing can be triggered if a “single intervenor simply proposes to use a different capital structure, regardless of whether the commission adopts the intervenor’s proposal.”

With 22 parties intervening in Westar’s last rate case and nine parties intervening in KCP&L’s, the commission said Great Plains and Westar would quickly lose control of the proposal, and promises to not charge ratepayers could be broken, the commission said. “Allowing the joint applicants to seek recovery of the acquisition premium if any party in any future Westar or KCP&L rate case proposes a different capital structure renders the … promise not to seek the acquisition premium from ratepayers hollow. An exception that is so easily triggered is an empty commitment,” the commission decided. “The exception is so open-ended as to render the joint applicants’ commitment not to seek recovery of the acquisition premium meaningless.”

The commission, which ruled after taking seven days of testimony, noted that of the 28 parties that intervened, all but the applicants opposed the merger.

Great Plains and Westar officials said they were reviewing the order to consider their next steps.

April 21, 2017

EIM Governing Body OKs Charter Expansion; Retains Schmidt

By Robert Mullin

Energy Imbalance Market (EIM) Governing Body members on Wednesday approved a measure that would give them increased power to make changes to the market’s governing charter.

CAISO’s Board of Governors still has final say over the measure, which revises the charter by granting the Governing Body “primary” authority over “substantive” changes to the charter.

EIM governing body charter — Schmidt | © *RTO Insider*

ISO approval didn’t appear in doubt based on discussion during an April 19 meeting at which the body also approved a new term for member Kristine Schmidt and named Doug Howe the new chair. “I think this is where the charter needs to be,” CAISO senior counsel Greg Fisher said.

The provision would require that substantive modifications be first presented to the body for its “advisory” input, similar to the role body members play regarding CAISO market rule changes that also affect the EIM. Changes approved by the body would advance to the consent agenda of the ISO board, which reserves the option to consider any decisions. (See EIM Charter Changes Would Give Governing Body More Power.)

The proposal would also allow the Governing Body to initiate any modifications to those areas of the charter dealing with the EIM’s Body of State Regulators (BOSR) and Regional Issues Forum (RIF), two West-wide groups established by the ISO to monitor and provide feedback on the EIM’s activities.

CAISO management initiated the changes at the request of Governing Body Chair Kristine Schmidt, who sought to clarify the body’s role in altering the charter — something not spelled out in the document itself.

“Through conversations when we had the Body of State Regulators and the Regional Issues Forum meetings in Las Vegas, the question kept coming back about who approves the charter changes,” Schmidt said.

She added that “in my head, I thought the EIM Governing Body would have the primary authority over” the charter based on what was spelled out in the EIM’s “guidance document.” That document — the creation of which was recommended by the EIM’s stakeholder Transitional Committee — defines the lines of decisional authority between the Governing Body and the ISO board over matters affecting the EIM operation and policies.

Schmidt took the issue to CAISO CEO Steve Berberich and General Counsel Roger Collanton, who agreed with her that “given the spirit and intent” of the guidance document, “there seems to be a place for the EIM Governing Body to have the primary decision authority over certain parts of that charter,” especially those sections related to the BOSR and RIF, she said.

BOSR Chair Ann Rendahl, a member of the Washington Utilities and Transportation Commission, threw her group’s weight behind the charter revisions.

“I appreciate the effort by the ISO staff and Chair Schmidt and the Governing Body in focusing on the charter,” Rendahl said. “We support the changes.”

The ISO board is expected to vote on the charter revisions during its May 1 meeting.

Schmidt to Remain as Howe Takes Chair

Also in the meeting, the Governing Body voted to keep Schmidt within its ranks — this time for a full term.

“I want to welcome you to three more years of captivity,” fellow body member Howe joked after the group took the vote. The five-member body also elected Howe — currently the group’s vice chair — to be its leader after Schmidt declined to seek another term as chair. Valerie Fong will assume the position of vice chair.

Schmidt’s reappointment was recommended earlier this month by an EIM nominating committee consisting of regional stakeholders — the same panel that initially selected her for the role after an extensive vetting process. (See EIM Panel Backs Schmidt for 2nd Governing Body Term.)

While Governing Body members typically serve for three years at a time, the EIM’s charter calls for staggered terms. A random selection process administered when the group was first seated last year left Schmidt with a one-year stint scheduled to end this July.

Although she actively sought another term on the body, Schmidt turned down another term as chair. “I just feel that there are four other people here who are so qualified and so fantastic as leaders, and also body members. I wanted to make sure that others had the opportunity to play this role” as chair, she said.

“You did an incredible job of getting us on track here and getting us organized … and we’re very fortunate that you stepped up for our first year,” Fong said.

In speaking about his own elevation to the position of chair, Howe said he could not resist a “good pile-on” in lauding Schmidt’s previous work in the role.

“I think most of you have seen Kristine in action over this past year, and more dedication and more effort would be hard to find in anyone,” Howe said. “It is going to be a daunting task to live up to her standard.”

April 19, 2017

NextEra not Giving up on Oncor Deal

By Rich Heidorn Jr.

Attorneys for NextEra Energy and Energy Future Holdings told a bankruptcy court hearing Monday that they are not giving up on NextEra’s bid to acquire Oncor despite Texas regulators’ rejection of the deal.

NextEra is “exploring every alternative and action to try to resuscitate the deal,” NextEra lawyer Howard Seife said during a hearing for EFH at the U.S. Bankruptcy Court in Wilmington, Del., The Wall Street Journal reported.

EFH attorney Chad Husnick told the court that NextEra is attempting to negotiate a settlement with large energy users that had urged the Public Utility Commission of Texas to block the acquisition.

The PUC voted unanimously April 13 to reject the $18.7 billion deal for Oncor, which is central to parent company EFH’s bid to exit Chapter 11 bankruptcy proceedings.

puct, nextera, oncor, luminant, txu energy — | *Oncor*

The commission said it would not approve the deal without restrictions on NextEra’s ability to appoint and replace members of Oncor’s board of directors and the board’s ability to limit dividends or other “upstream distributions” from Oncor. The PUC said those two ring-fence provisions had insulated Oncor from EFH’s bankruptcy. (See Texas Commission Denies NextEra’s Bid for Oncor.)

Judge Christopher Sontchi expressed frustration over the PUC’s rejection of the deal — the second time in a year that the regulators blocked an Oncor acquisition. Last May, Dallas-based Hunt Consolidated withdrew its bid to acquire Texas’ largest transmission and distribution service provider over PUC conditions it found too onerous.

“The PUC seems unconcerned with the resolution of the bankruptcy estate as a factor in making its determination,” Sontchi said Monday, according to Bloomberg. “I find that concerning.”

NextEra has until May 8 to file a motion for rehearing with the PUC. It could also file a court challenge, Husnick said.

Sontchi and EFH lawyers agreed that the PUC’s insistence on retaining local control of Oncor is reducing the company’s value to potential acquirers.

The proceeds from the sale of Oncor would have been split among EFH’s creditors, who reached a settlement last year to end EFH’s $42 billion bankruptcy.

If the NextEra deal cannot be revived, EFH may have to seek a new exit that issues equity in Oncor rather than cash. The Journal reported that trading prices on EFH’s junior debt fell after the PUC’s rejection.

Another option would be a public offering of the stock. “It’s been difficult to please both bondholders and regulators,” Morningstar analyst Andrew Bischof told Bloomberg last week. “An IPO may be their best option at this point. If Texas regulators aren’t going to be a little more flexible, then an IPO is more likely.”

April 19, 2017

AEP Must Install Scrubbers at Indiana Coal Plant, Court Rules

By Amanda Durish Cook

American Electric Power must bear the billion-dollar cost of installing scrubbers at the Rockport Generating Station in Indiana, an appellate court said, ruling in favor of the plant’s owners in a dispute over a lease contract.

A three-judge panel for the 6th U.S. Circuit Court of Appeals ruled April 14 that it’s the duty of plant operator AEP Generating ― not the plant owners’ trustee, Wilmington Trust ― to install court-ordered emissions-reducing technology at the coal-fired Rockport Unit 2 (No. 16-3496). The decision overturns an earlier district court ruling.

Rockport Generating Station Units 1 and 2 | © *John Blair*

Rockport Unit 2 supplies about half of the output of the 2,620-MW plant on the Ohio River in southern Indiana.

Wilmington Trust charged that AEP subsidiaries Indiana Michigan Power and AEP Generating are responsible for the costs of a selective catalytic reduction (SCR) device on Rockport 2 for NOx control. Under a consent decree to settle Clean Air Act violations with EPA and several other parties, the approximate $1.4 billion SCR for Rockport 2 is required by Dec. 31, 2019.

Indiana Michigan Power and AEP Generating jointly operate the two Rockport units despite the fact that AEP sold Rockport Unit 2 to a group of investors in 1989. The investors in turn leased the unit back to the AEP subsidiaries for 33 years, ending Dec. 7, 2022.

In 2013, EPA and other parties agreed to modify the consent decree to allow AEP to instead install a less expensive emissions control by April 16, 2015, and then either install the expensive scrubber, retire the plant or switch it to another fuel by the end of 2028, six years after the current lease expires.

Wilmington Trust filed suit against AEP soon after, claiming the modified consent decree breached the lease by imposing an impermissible lien and by taking an action “that materially adversely affected the economic useful life of Rockport 2.”

Clauses in the complex contract prohibit AEP from taking action that “will materially adversely affect the operation, safety, capacity, economic useful life or any other aspect of Unit 2” and from creating or incurring liens, except in certain circumstances.

The appellate judges found that AEP’s financial promises to Rockport would be empty after the lease expires and said AEP’s settlements with EPA were its own responsibility. They said applying a temporary fix and pushing back a permanent solution would make Rockport’s owners essentially “responsible for the costs associated with either upgrading Rockport 2 or shutting it down.” The lease states that the operating AEP subsidiaries are responsible for “installing, owning and operating” major environmental controls to comply with regulations.

“AEP traded away Rockport 2’s long-term value in exchange for a more favorable settlement of claims against their other interests,” the judges said of the 2013 consent decree modification. AEP had argued that deferring the scrubber’s installation was not only good for itself, but also for the owners, as either party would have several more years of profit before a scrubber was required. The judges rejected the argument, saying the plant’s owners were not part of the modification.

It’s unclear if AEP’s lease will be extended. Completed in 1989, Rockport 2 has an expected useful life anywhere through 2034 to 2049, according to the order.

April 19, 2017

LA Creating Aggregator to Compete with SoCalEd

By Robert Mullin

Electricity customers in Los Angeles County will soon have the option to purchase their power from a new publicly run supplier that will obtain more of its energy from renewable resources.

The county’s Board of Supervisors voted 5-0 on Tuesday to establish a community choice aggregator (CCA) that will directly compete with Southern California Edison for the region’s retail, commercial and industrial customers.

The supervisors authorized initial spending of $10 million to launch the Los Angeles Community Choice Energy (LACCE) Authority, with 80% of those funds slated for procuring power, and the balance used for covering administrative costs.

The new CCA will serve electricity users in the county’s unincorporated areas, as well as incorporated cities without a municipal utility, such as Long Beach, South Pasadena and Torrance. Customers in participating areas will be automatically enrolled in the program but can opt out and maintain service with SoCalEd.

Long Beach waterfront | *Visit Long Beach*

Customers of the municipally owned Los Angeles Department of Water and Power, Pasadena Water and Power and Burbank Water and Power will not be eligible to make the switch.

The motion voted upon by the board said the initiative will “bring significant environmental and financial benefits to the region, and reflects the growing state- and nationwide trend toward providing customer choice in the provision of electricity.”

SoCalEd Renewable Resources — Kuehl | *campaign website*

A report presented to the board last year showed that a countywide CCA would be financially viable and could provide customers power that is cheaper and “significantly greener” than that delivered by SoCalEd, an investor-owned utility serving much of the region. The county would aim to purchase 50% its energy from renewable resources, nearly double that of SoCalEd. That would reduce countywide greenhouse gas emissions by 850,000 metric tons — or 9%, the county estimates.

“There are few, if any, single actions that the county could take that would have such a large and immediate impact” on the environment, the county’s Chief Executive Office said in a report issued earlier this month.

SoCalEd said it maintains a “neutral” position on CCAs.

The county expects to roll out the CCA’s operations in three phases starting in January 2018, when the LACCE Authority will begin delivering electricity to county-run facilities in unincorporated areas.

Phase two will kick off in July 2018 with the CCA offering service for commercial, industrial and municipal customers in unincorporated areas and cities that elect to become initial participants in the authority, a move that is expected to bring on about 200,000 new accounts.

A third phase launched in 2019 would begin providing service to approximately 1.5 million residential customers.

County officials began exploring the creation of an electricity provider last year. California currently has eight CCAs, with seven more scheduled to begin operations this year. A 2002 state law enabled the creation of CCAs, which rely on the existing distribution system to deliver electricity to customers.

Growth of CCAs is one factor prompting California energy officials to reconsider the idea of instituting retail choice in the state’s electricity market, an effort that was abandoned in the aftermath of the 2000/01 Western Energy Crisis. (See California to Reconsider Retail Choice.)

April 18, 2017

SPP Hopes Congestion Rights Rule Change Wins FERC OK

By Tom Kleckner

TULSA, Okla. — SPP’s Markets and Operations Policy Committee approved a revision request to comply with FERC guidance on the RTO’s disparate treatment of point-to-point (PTP) and network integration transmission service (NITS) during periods of redispatch.

MRR202 would allow NITS to be eligible for auction revenue rights for limited times of the year and only for the service not subject to redispatch. NITS would not be eligible for long-term congestion rights (LTCRs), because it does not have continuous service for the entire transmission congestion rights year.

The change is in response to FERC’s September order that raised concerns that allowing network service subject to redispatch prior to necessary upgrades being constructed could result in a decrease in allocated ARRs for other transmission customers, along with their ability to nominate LTCRs. The commission ordered a Section 206 proceeding and directed SPP to limit the eligibility for network customers’ ARRs and LTCRs with service subject to redispatch. (See FERC: SPP Treating P2P Customers Unfairly on Congestion Rights.)

“Our preliminary review indicates that SPP should not provide network service customers subject to redispatch with any LTCRs until the transmission upgrades are placed into service and the service is no longer subject to redispatch,” FERC said in the order (ER16-1286, EL16-110). “The commission notes that this approach would be consistent with SPP’s rationale for not providing point-to-point customers subject to redispatch with LTCRs.”

The 206 proceeding sought to determine whether NITS subject to redispatch while necessary transmission upgrades are being constructed should warrant the same treatment as PTP. SPP responded in December, asking that it be allowed to run the issue through the stakeholder process before FERC takes action.

Stakeholders rejected SPP’s recommended approach to allow ARRs until the end of the allocation year following the revisions’ effective date. With the change, eligibility limitations only apply to new NITS service after effective date, and current NITS service is “grandfathered” to receive current treatment for the service’s term.

SPP staff said it was concerned with the network service exemption because it interprets the order to mean that FERC is exempting awarded ARRs, and future nomination processes should treat NITS and PTP similarly.

“The way we interpret it, FERC is saying any firm transmission service with redispatch should be able to nominate for ARRs or LTCRs, period,” said Richard Dillon, SPP’s director of markets. “You can’t pull them back, but you don’t issue any more.”

Enel was the lone member to oppose the motion, saying the Tariff changes should apply prospectively to FERC’s refund date of Sept. 29, 2016. It proposed its own approach to a LTCR allocation methodology, which it said would ensure firm customers not subject to redispatch are given priority eligibility.

“We believe FERC was very clear that SPP’s method of allocating ARRs and LTCRS is unjust and unreasonable,” said Enel’s Lisa Szot.

Oklahoma Gas and Electric’s David Kays, chair of the Regional Tariff Working Group, said about 75% of the stakeholders’ recommended language aligns with FERC’s directive. “Where it’s different is the next allocation period,” he said. “That’s where it deviates from FERC’s suggested language.” The working group backed the changes.

Asked why SPP did not just use FERC’s suggested language, Dillon said the commission’s language is “80% of the way there.”

“We added … a single sentence that grandfathered the historical network dispatch,” he said. “FERC found that ARRs granted to customers should not continue past the current year. We’re saying that the effective date should be as of Sept. 29, 2016, or the date FERC issued its order in this proceeding.”

Staff said the commission intends to issue a final order by May, assuming it has a quorum by then.

April 18, 2017

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — Power demand proved difficult for PJM operators to forecast in March as a snowstorm was followed by exceptionally warm weather, RTO staff told participants at last week’s Operating Committee meeting.

“That was the story of March: a lot of up and down,” PJM’s Chris Pilong said.

The balancing authority area control error limit (BAAL) performance score dipped to 99.4%, the lowest it’s been since last March, PJM’s Ken Seiler said, with 257 excursion minutes. The BAAL was high in some cases, suggesting that plants were over-generating, he said. The longest excursion lasted nine minutes.

“This is eerily similar to what we had last year,” he said.

A 24-minute spinning event on March 23 occurred when market-to-market constraints in MISO prevented PJM from loading combustion turbines from the west, as the RTO had planned, Pilong said. PJM is looking at the event to determine which units responded and which did not, Seiler said.

PJM’s perfect dispatch performance is 76%, which is about six percentage points lower than it was at this time last year.

PJM Wants to Study Frequency Response

PJM is proposing a problem statement and issue charge to understand why many generating units either aren’t providing frequency response or are responding incorrectly to signals from the RTO.

While frequency response is essential for grid reliability, a 2012 NERC report found that only 30% of units were providing primary frequency response, PJM’s David Schweizer said. FERC published a Notice of Proposed Rulemaking on the topic in November that would require all new units, excluding nuclear, to provide the service. The commission is considering the comments it received. (See FERC Seeking Comments on Primary Frequency Response.)

In a survey of its generators last year, PJM found that, among its critical load resources — generators with a four-hour or less hot start time — just 95% have a functional governor, 75% are using NERC-recommended settings and 25% are using controls that override frequency response.

Other grid operators, including CAISO, MISO and ISO-NE, have requirements consistent with NERC reliability standards, PJM said.

The new rules, which PJM would be looking to implement for all units, would comply with NERC standards and might also include compensation, even though the NOPR didn’t propose that.

PJM had suggested separating the components across the Operating and Market Implementation committees, but stakeholders were adamant that they should be kept together to ensure any market signals are designed to incent the desired behavior.

A PAR Too Far?

PJM and NYISO are still interested in replacing a broken phase angle regulator at Consolidated Edison’s Ramapo substation, despite stakeholder skepticism about its necessity. The grid operators are holding a meeting Tuesday at NYISO’s offices to discuss the situation and consider modifying their joint operating agreement. The joint stakeholder interactions are intended to create criteria for a benefits analysis that would factor in the cost allocation of any remedies. (See PAR Wars: A Struggle for Power.)

PJM’s Stan Williams walked through a presentation NYISO created on the issue, in which the ISO urges replacing the PAR.

“They see enough benefit there that they want to move ahead with replacing the second PAR by the fall,” he said.

pjm operating committee frequency response — Borgatti | © *RTO Insider*

Williams said the joint stakeholder engagement will be beneficial as it might create a roadmap for future cross-border projects. PJM uses a similar benefits analysis with MISO in determining transmission, he said. Gabel Associates’ Mike Borgatti asked PJM to develop a presentation on how that process works.

Carl Johnson of the PJM Public Power Coalition and Calpine’s David “Scarp” Scarpignato complained about the PAR meeting being scheduled on one of PJM’s only two no-meeting days of the month. Both said they will be unable to attend.

“You’re going to have a one-sided meeting. It only happens once a month,” Scarp said.

Dave Pratzon of the GT Power Group supported PJM’s engagement with NYISO on the issue, pointing out that the RTO objected when MISO attempted to make PJM pay for PARs installed on the Michigan-Ontario border.

PJM Seeking Feedback on Fuel-Security Report

Vice President of Operations Mike Bryson walked through a paper PJM released last month on fuel security in the RTO and asked for stakeholder feedback. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)

Although the paper found a capacity mix of more than 20% solar would threaten reliability, Bryson noted that currently renewables only make up about 2% of the mix.

The paper was very narrowly focused, he noted, and purposefully didn’t address other topics, such as environmental issues or whether natural gas infrastructure could keep pace with the high percentage of gas-fired generators PJM’s analysis said the fleet could handle. The paper did not identify a percentage of gas-fired units that would threaten reliability.

Additionally, it didn’t consider dual-fuel units or units with access to multiple fuel pipelines. It also assumed that all units had confirmed supply contracts.

FirstEnergy’s Jon Schneider pointed out that the study highlighted only a third of the portfolios that PJM considered “desirable” would be resilient enough to withstand polar vortex-type conditions, which the study attributed to “the increased risk of natural gas delivery under extremely cold and high load conditions.” He asked for clarity on assumptions made regarding gas supply since it can be either firm or interruptible.

Bryson acknowledged that the study assumed firm service for all units and said that the results would factor into PJM’s planning going forward.

Scarp said many gas units have access to multiple pipeline sources and that, despite coal units maintaining a 30-day onsite fuel supply, many such piles were frozen and unusable during the 2014 polar vortex and recalled a similar period in 1994 that resulted in rolling blackouts.

“Just because you have a 30-day inventory doesn’t mean you have supply for 30 days,” he said.

— Rory D. Sweeney