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.
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.
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.
Fisher
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.”
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.
| 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.”
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 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.
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.”
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.
Thomas | LA County Government
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.)
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.
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.
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.
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.
VALLEY FORGE, Pa. — With several changes under consideration for its financial transmission rights processes, could PJM be forming another FTR task force?
PJM convened task forces in 2011 and again in 2015 to address FTR underfunding.
At Wednesday’s Market Implementation Committee meeting, Direct Energy’s Jeff Whitehead presented a proposed problem statement and issue charge to address the allocation of day-ahead surplus congestion funds and FTR auction revenue surplus funds.
Other stakeholders immediately questioned the proposed language, concerned that it seemed to “presuppose” a solution. Whitehead and other sponsors of the problem statement, including Steve Lieberman of American Municipal Power and John Rohrbach of ACES, representing the Southern Maryland Electric Cooperative, agreed to revise it.
PJM’s Asanga Perera supported the proposal, saying the RTO attempted to implement it but was told by FERC it should go through the stakeholder process. Independent Market Monitor Joe Bowring favored it as well.
Barry Trayers of Citigroup Energy felt it remained too narrowly focused. “There’s a lot of moving parts and this misses a ton of them,” he said.
Whitehead defended the initiative, saying FERC narrowed the scope with its September order directing PJM to allocate balancing congestion costs to real-time load. By removing a major source of FTR underfunding, he said, the existing funding sources can be reviewed and removed if unnecessary. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix.)
“But I guess we’re going to talk about that in the FTR task force,” Whitehead said.
| PJM
His issue charge does not call for creating a task force — instead suggesting the issue be addressed by the MIC.
But there are other FTR issues pending as well. Later in the meeting, Perera discussed several other FTR updates, including additional information on the delayed results for the March 2017 FTR auction. He said he asked other RTOs about their processes.
“They all said PJM’s process is extremely complicated,” he said. “None of them have any overlapping periods like we do.”
Perera proposed removing the single quarterly auction that overlaps monthly auctions or developing software upgrades to speed up the solution time. (See “FTR Lateness Blamed on High-Volume Period,” PJM Market Implementation Committee Briefs.)
“Hardware, software, market structure — there are things that can be done better than the one-off solution of killing one quarter,” DC Energy’s Bruce Bleiweis said.
“The IMM supports PJM’s proposal to remove the overlapping-period quarterly auction as a solution to the issue, at least as a stop-gap measure. The monthly component product periods of the quarter will still be available and market-sensitive auction results will be made available on a more timely basis,” said Howard Haas, the Monitor’s chief economist.
TULSA, Okla. — SPP COO Carl Monroe told the Markets and Operations Policy Committee last week that allocating costs for existing transmission facilities would not be an issue should the Mountain West Transmission Group be successful in its quest for RTO membership.
Mountain West doesn’t expect to pay for SPP’s facilities “past or present,” Monroe said, and SPP is “thinking similarly.”
“We have a current situation within SPP where we’re not sharing costs of the upgrades across the Eastern and Western Interconnections,” he said. “There’s already a situation in the SPP Tariff that, through contract, load in the West doesn’t pay for Eastern upgrades. That makes sense, because they don’t get any electric benefits out of that.”
SPP and Mountain West are also trying to determine whether to operate as a single market or two separate markets. There are currently four DC ties between SPP and Mountain West facilities, with a total capacity of 710 MW. Mountain West’s membership would place all seven U.S. ties between the Eastern and Western Interconnections under SPP’s Tariff.
“We’re talking with vendors, technical staff and outside experts to see whether it’s possible to operate a market over DC ties,” Monroe said.
Monroe was unable to answer several questions from members, citing confidentiality issues. However, he welcomed stakeholders to participate in the Strategic Planning Committee’s executive sessions, where discussions on Mountain West’s potential membership will take place. (Members will have to sign non-disclosure agreements to participate.)
Monroe and Tri-State Generation and Transmission Association’s Mary Ann Zehr said Mountain West hopes to determine whether to continue pursuing membership before July. The two entities would begin drafting revisions to governing documents shortly thereafter, with the intention of getting SPP board signoff in January 2018.
The MOPC overwhelmingly agreed with staff’s recommendation to remove a Southwestern Public Service 345-kV line from the 2017 Integrated Transmission Planning’s 10-year assessment. The vote was opposed only by independent transmission companies ITC Holdings and Hunt Transmission, with Golden Spread Electric Cooperative and South Central MCN abstaining.
The MOPC and SPP’s board directed staff in January to further evaluate the Texas Panhandle project following pushback from SPS, which said it was “the wrong time” for the line. (See “Board Sends $144M Tx Project Back for Re-evaluation,” SPP Board of Directors/Members Committee Briefs.)
Staff’s further evaluation and modeling changes revealed a 6.5% decrease in the SPP region’s adjusted production costs savings, and a third-party review using more detailed routing assumptions lengthened the project from 90 miles to 109 and increased the $144 million cost estimate to $173 million.
In March, SPS parent Xcel Energy announced it would add 1,230 MW of new wind energy north of the proposed project in Texas and New Mexico. Load forecasts south of the constraint also indicated an 800-MW reduction in load, further reducing its need. The transmission line would run southwest of Amarillo to an SPS power plant being evaluated for continued operation.
“It’s a balancing act. We have to get it right,” said Engineering Vice President Lanny Nickell, responding to comments about the additional modeling and studies. “We’ve probably done more analysis on this single ITP10 than we’ve done on any number of studies cumulatively. … We need to get better at interpreting these results.”
“I look at planning as a core fundamental of the RTO,” said MOPC Vice Chair Todd Fridley of Transource Energy. “If we can’t do that well and have these fits and starts, we’re not getting the job done.
“Major input changes at the end of the planning process makes this determination more difficult. Everyone wants to build the right projects, but we must also maintain the integrity of the planning process so that everyone has confidence that we are delivering customer value,” Fridley said.
ITC Holdings’ Alan Myers, who chairs the Economic Studies Working Group that brought forward the staff recommendation, reminded members that SPP’s new transmission planning process will include accountability mechanisms designed to promote timely data exchanges, reviews and approvals. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)
“One of the core tenets in the new process is more stakeholder discipline,” he said. “There will be some bright lines about when we need to have your data in. What we have here is a little more unprecedented.”
“What SPP did was go back and do a fair assessment with the stakeholders that were involved,” said Bill Grant, director of strategic planning for SPS. “This evaluation is showing that, yes, if we had 8 [GW] of wind, transmission has to be built.”
MWG Closing out MMU’s Recommendations
The Market Working Group took another step toward closing the 2014 State of the Market Report’s nine proposed market changes by securing approval of a revision request that removes the day-ahead must-offer requirement.
The change request, MRR125, came out of the Market Monitoring Unit’s recommendations to improve the Integrated Marketplace and was designed to run in parallel with revisions to physical withholding rules. The MOPC declined to take up the revision request in July to allow for further discussion on the rules. (See “MOPC Defers Action on Must-Offer Rule,” SPP Markets and Operations Policy Committee Briefs.)
Working group Chair Richard Ross of American Electric Power said the group spent considerable time since then discussing the issue. In February, it rejected a revision request that would revise the physical withholding rules to include a penalty for noncompliance. The MMU has appealed that decision and plans to bring it up at the July MOPC meeting.
“The conclusion was a preference to stay with current monitoring activities,” Ross said. “It’s important you realize whether these provisions are in or out, you’re still subject to physical withholding” prohibitions.”
MMU Director Alan McQueen was asked if the unit agreed with the MWG’s conclusion.
“We think the market has the right incentives,” McQueen said. “[MRR125] doesn’t eliminate concerns around potential cases of physical or economic withholding in the market. We think the rules can be improved, but we don’t think the day-ahead must-offer significantly contributes to that.”
MOPC Chair Paul Malone, with the Nebraska Public Power District, asked McQueen whether he had any concerns over “after-the-fact” market power.
“[Market participants] may not know when they have local market power,” McQueen said, “but generally, from experience, MPs should be able to discern when they’re likely to have market power.”
“The [MWG’s] concern was there may be particular conditions on the grid, like transmission outages, planned and unplanned, where a unit may find itself in a situation where it has market power,” Ross said. “The concern on MPs’ part was we may not be as smart as the MMU staff thinks we are.”
Ross said eight of the nine 2014 recommendations are closed, though McQueen disagreed.
“Richard represents the MWG, I represent the MMU,” he said.
McQueen took the opposing side when the MOPC then considered MRR214, which would allow market participants to add a 10% buffer to mitigated offers.
The MWG said the 10% buffer added to the mitigation offer will give MPs more margin for error when submitting their mitigated offer curve. The group also said the change would improve price formation in SPP’s markets by removing a penalizing feature that may be suppressing offered prices today.
“Mitigation and economic withholding are trying to keep the market at competitive levels when there is the presence of market power,” McQueen said. “Are we accomplishing that? Are we improving that? Are we making it better? Is this making sure the market stays competitive during those periods when mitigation actually goes into effect?
“What’s being proposed is inconsistent with what we’ve seen in other markets and what’s been approved by FERC,” he said.
“This came across because of a discussion at the Board of Directors,” said Golden Spread Electric Cooperative’s Mike Wise, who sits on the Members Committee and chairs the Strategic Planning Committee. “Many MPs have encouraged us to do this. They’re not recovering their short-term marginal costs.”
“This needs more work,” said Lincoln Electric System’s Dennis Florom. “I don’t see staff supporting it, I don’t see the MMU supporting it. We’re going to have our own members and the MMU fighting at FERC, which is embarrassing to me.”
The committee sent the revision request on to the board for its approval next week, with seven members opposing and five abstaining.
Separately, Ross recommended the committee reject RR201, which would have provided market participants a mechanism to settle day-ahead market errors without repricing and re-clearing the entire market.
“The challenge folks encountered was if we do that without resettling the whole market, you’re just throwing it in a bucket and spreading it across the whole market,” he said.
The MOPC agreed, though two members opposed and another dozen or so abstained.
Another change (MRR209) that would have expanded resources’ “status options” to include start-up/shut-down and testing was rejected on a roll-call vote, with 61% of the members opposed.
SPP staff said the change would “result in a clearer understanding” of why a resource may not be following dispatch instructions. However, it drew opposition from members who couldn’t balance the revision’s minimal benefits with its estimated $22,000 cost when operators will continue follow-up phone calls for reliability reasons.
The committee also approved MRR203, which adds a “last-chance” second set of auction revenue rights nominations in the monthly ARR process, where any source-to-sink path can be nominated.
MOPC Endorses Re-evaluation of Basin Electric Project
The MOPC endorsed Basin Electric Power Cooperative’s request for an expedited re-evaluation of a 345-kV project in northwestern North Dakota. The project — replacing a 33-mile, 115-kV line at an estimated cost of $52.3 million — was approved last July for a notification to construct with conditions (NTC-C) out of the 2016 Near-Term assessment. (See “First Competitive Tx Project Pulled; ND 345-kV Line Approved,” SPP Board of Directors and Members Committee Briefs.)
Basin Electric had projected 2.5% load growth in the nearby Bakken shale play in making its earlier request, but updated load forecasts from its member companies have revised that number downward. It asked for the expedited assessment to confirm the timing of construction and associated financial expenditures.
“We’re still seeing load increases in that area, just not at the rate we anticipated,” said Jason Doerr of Basin Electric member Northwest Iowa Power Cooperative. “It’s still Basin Electric’s belief that this load will continue to grow at a rate that’s significantly less. Next year, wherever the economy goes, we’ll have another load forecast to provide SPP.”
SPP’s Jason Davis said the project could eventually fall under FERC Order 1000, but until then, “We want to take a step back, see what needs and issues still exist going forward.”
Another project did proceed as a potential seams project, with the MOPC’s approval of a 50-MVAR reactor at a 345-kV substation near Springfield, Mo. The Seams Steering Committee and Transmission Working Group both recommended the project’s approval out of the regional-review process. The project was identified last year in a joint study with Associated Electric Cooperative Inc.
The MOPC also approved the TWG’s 2017 ITPNT, which includes 16 reliability projects at a combined cost of approximately $60 million, and its scope for the 2018 ITPNT. Both motions passed unanimously.
Cost Allocation Review Cycle Could Extend to 6 Years
The MOPC approved a task force’s unanimous recommendation and an accompanying revision request that future regional cost allocation reviews (RCARs) be conducted at least once every six years, doubling the previous three-year timeline.
The Regional Allocation Review Task Force said extending the timeline would save SPP manpower and consulting costs, noting the most recent RCAR showed an increase in benefit-to-cost ratios and only one entity below the threshold. Ross, the RARTF’s vice chair, pointed out the Tariff still allows members to seek relief for an out-of-cycle RCAR at any time from the board, MOPC or Regional State Committee.
“It’s not a trivial task. We’re spending well over $400,000 to produce the reports,” Ross said. “It is quite literally a single-word change.”
The motion was opposed by the City of Springfield, whose transmission zone in southwestern Missouri was found to be deficient by RCAR II, and several other smaller entities. The Morgan project — a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a connecting 161-kV line at an estimated $9.2 million — was approved out of the 2017 ITP10 in January as a remedy to Springfield’s deficiency, and was recommended for regional funding by the MOPC last week. However, the project is contingent on reaching an agreement with AECI, which would not see reliability benefits from a potential seams project that sits within its service area.
Jeff Knottek, director of transmission planning and compliance for Springfield utilities, said if the Morgan project doesn’t provide the city with a remedy, it didn’t want to wait another six years.
“We’re still technically a harmed entity through two RCARs,” said Knottek, who abstained from the vote. “We haven’t climbed out of the hole yet, and [Morgan] could fall on its face. Under a worst-case scenario, in six more years we could be sitting [at a negative number].”
Changes Proposed for Revision Process
SPP staff introduced potential changes to the revision-request process for technical documents that don’t require MOPC approval.
Staff said NERC reliability standard IRO-010-2, which requires the reliability coordinator (RC) to maintain documentation of data specific to its responsibilities, and a recent revision request that would create RC and balancing authority data as an appendix to the operating criteria, created a need to manage other documents not a part of the current process.
While the revision process for technical documents would not require MOPC approval before being enforced, the committee would still hear appeals from members. Written reports on the changes would be provided in the MOPC’s background materials, and members could request discussion on the changes if they’re not part of the working groups responsible for the documents.
Staff said the revised process would better meet NERC requirements and proposed starting with reliability data specifications and the communication protocols. Other documents that could fall into the process include the Integrated Transmission Planning manual, the balancing authority’s emergency operations plan, the SPP Reliability Coordinator Area’s restoration plan and other technical handbooks and guides.
Several stakeholders, primarily from smaller members, expressed concerns over losing visibility into changes.
“Letting [the documents pass] out of the primary working group … how would we know they have passed?” asked ITC Holdings’ Marguerite Wagner. “How would we keep track of that?”
“As the organization gets bigger and bigger in geography and more members, I’m not comfortable with this,” said Chairman Malone, referring to extending the process to other SPP documents. “In our organization, we try to have someone plugged in to every working group, but not everyone can do that. I’m just not comfortable with it yet.”
Monroe said the primary working groups and staff would be responsible for notifying all parties of pending changes, and that some of the more technical revisions would be included on the MOPC consent agenda. He also said he had heard support for giving the working groups the ability to approve technical documents, rather than send them to the MOPC.
Staff said it will return with a formal proposal for the committee’s July meeting.
Paul Suskie, SPP’s legal counsel and corporate secretary, shared the Corporate Governance Committee’s proposed bylaw change for organizational group chair and vice chair selections.
Under the changes, group chairs would be nominated by the committee and appointed by the board to a term that coincides with the board chair’s two-year term. Vice chairs are elected by the groups’ members, with their terms now coinciding with the group chairs’. The MOPC vice chair would be elected by the board.
Should there be a vacancy at the chair level, the vice chair would become the interim chair until a replacement is appointed by the board to fill out the remainder of the term.
The working group leadership’s terms would be staggered to expire in even or odd years. Committees reporting to the board would have their leadership’s terms match that of the board chair. This doesn’t apply to those committees advising the board, such as the Regional State Committee and the Cost Allocation Working Group.
Upon board approval, the bylaw changes would be filed with FERC for its approval.
MOPC Approves Doubling Credit Allowance to $50M
SPP will join its RTO/ISO brethren in adopting a $50 million unsecured credit allowance should the board next week approve a revision request raising its current cap from $25 million.
SPP is the last of the RTOs without a $50 million allowance cap. CPWG-RR218 calls for raising the allowance to reduce the costs of capital for utilities, while exposing SPP’s customers to “minimal additional credit default risk.”
FERC Order 741 allowed RTOs and ISOs to grant up to $50 million in unsecured credit, a limit most grid operators have adopted.
The Credit Practices Working Group’s revision was pulled from the consent agenda over concerns that SPP was planning to raise its cap just to match other RTOs. However, staff said SPP’s transmission congestion rights market, with its collateral requirements, highlighted the need to revisit the cap.
Staff estimated the increase would affect about 15 credit customers. The revision was approved unanimously by the MOPC.
Twelve other revision requests also passed unanimously as part of the consent agenda:
BPWG-RR207: Aligns the business practices with the Integrated Marketplace’s tag-denial criteria.
MWG-RR200: Allows bilateral settlement statements (BSS) at a withdrawal point to be included in the overcollected losses calculation. Capping the BSS at the maximum amount of the real-time withdrawal minus any amount of grandfathered agreements or any federal service exemptions will diminish the dilution at a generation or hub settlement location.
MWG-RR205: Allows the implementation of the combined-resource option changes by including the minimum regulation-capacity operating limit, and adds resource offer parameters that can be changed daily for a jointly owned resource’s minimum physical capacity and physical-regulation capacity operating limits.
MWG-RR216: Reinstates Tariff language omitted from RR173 and filed at FERC last year related to eligibility of multi-configuration resources for regulation-up or regulation-down service.
MWG-RR217: Removes Tariff language related to violation relaxation limits to make the section consistent with a compliance filing to FERC’s Order 825 on shortage pricing.
MWG-RR219: Ensures language in SPP’s Tariff meets FERC requirements for enhanced combined cycle units.
ORWG-RR213: Creates a new appendix to the SPP Operating Criteria that defines how the SPP reliability coordinator will operate voltage stability limited system constraints, as recommended by the Wind Integration Study.
RTWG-RR208: Implements the Transmission Planning Improvement Task Force’s white paper for new regional planning processes by replacing current planning schedules with an annual transmission-expansion plan, creating a standardized scope; establishing a common planning model for use across the various planning processes; and creating a staff/stakeholder accountability program. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)
RTWG-RR211: Establishes an additional criterion for competitive projects, requiring that the total competitive segments for a transmission project cost meet or exceed $3 million.
TWG-RR224: Aligns the existing criteria with NERC’s new definition of special protection schemes as remedial action schemes, and cleans up planning-criteria language coinciding with changes made to the operating-horizon system operating limits methodology.
VALLEY FORGE, Pa. — FERC did not act on PJM’s proposed changes to its shortage pricing, so revisions for how to handle transient shortages will go into effect May 11 as planned, Manager of Real-time Market Operations Lisa Morelli told the Market Implementation Committee on Thursday. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
The curve step changes are still on track to be implemented on July 1, but it’s unclear whether that will definitely happen.
“There’s unfortunately uncertainty [about] a lot of what’s happening at FERC right now,” PJM attorney Steve Shparber said. “We will keep going on until we hear otherwise.”
PJM’s plan would change the scarcity signal for the maximum $850 penalty factor from the economic maximum of the single largest contingency to the highest actual output of a single unit. Next, it would add two lower “steps” that would trip a $300 pricing level. One step would be calculated as the highest actual output plus 190 MW — a static number derived from the synchronous reserve mean of the Mid-Atlantic Dominion zone plus one standard deviation. The second step would be calculated as the previous step plus an extension.
PJM to Review Black Start Prior to New RFP
PJM released its first request for proposals on black start units in 2013 to have them in place by 2015. As part of that process, the RTO instituted a five-year review, meaning the next black start RFP will be in 2018 for projects to be available in 2020.
To begin that process, staff will be holding a special one-hour session after the May 2 Operating Committee meeting to review results and lessons from the first RFP. Stakeholders pointed out that that is the second day of the FERC technical conference on the impact of state policies on RTO operations in PJM, ISO-NE and NYISO (AD17-11). PJM staff promised the meeting will be quick.
Earlier in the meeting, stakeholders endorsed changes to the annual revenue requirements for black start units. PJM and its Independent Market Monitor came to an agreement on having the revenue go into a non-interest-bearing account for each unit until its costs have been approved, at which point the RTO will conduct a true-up.
