FERC last week denied NRG Curtailment Solutions’ request for an exemption from NYISO penalties for nonperformance and invalid generator registrations on approximately 13% of its New York capacity obligations in May 2016 (ER17-834).
NRG argued that uncertainty about EPA emissions regulations compromised its ability as a Special Case Resource (SCR) to help the New York grid operator balance shortfalls in delivered capacity contracts.
SCRs are demand-side resources that agree to reduce load at the ISO’s instruction, using either curtailments or “local” generators — ones intended to self-supply a load and that do not supply the distribution system. As a “responsible interface party,” NRG Curtailment aggregates individual SCRs for the ISO.
An EPA rule change in 2013 allowed reciprocating internal combustion engines (RICE) providing emergency DR to run without extra emissions controls for up to 100 hours per year in emergency demand response programs, up from the previous limit of 15 hours annually. In 2015, the D.C. Circuit. Court of Appeals vacated and remanded the 100-hour exemption. (See Appellate Court Rejects EPA Rule on Back-Up Generators.) EPA was granted a stay of the D.C. Circuit’s decision until May 1, 2016.
On April 15, 2016, EPA issued guidance that RICE generators may not operate for any period of time unless they meet emission standards for nonemergency engines. On May 2, 2016, the D.C. Circuit issued a mandate implementing its earlier decision.
NRG said it only enrolled generators in the May 2016 installed capacity auction that would participate for 15 hours or less because it believed that the 15-hour rule would be reinstated with the elimination of the 100-hour rule. The company said it had no ability to withdraw resources that no longer complied with the revised emissions rule but that it stopped selling capacity from DR resources with noncompliant generators for the June 2016 auction.
Increasing Emissions Stringency
NYISO opposed NRG’s waiver request in a filing in February, arguing that EPA’s intent to apply more stringent emissions requirements was apparent beginning in July 2015, contrary to the company’s contentions. The ISO said EPA’s motion to stay indicated that the agency clearly intended not to revert to its 15-hour limit.
While NRG may not have intended to enroll ineligible resources, NYISO said, if the company was unsure, it could have waited until EPA had clarified its position. The ISO believes that NRG assumed the risk of noncompliance and therefore should be subject to the penalty provisions of its Tariff.
NYISO said that while it had not yet determined whether penalties were “appropriate” for NRG’s capacity sales for May 2016, “sales by invalidly enrolled SCRs would be subject to a penalty.” In addition, an aggregator can be penalized when its unforced capacity sales exceed the greatest quantity megawatt reduction achieved during a single hour in a performance test or event called by the ISO.
FERC ruled that granting the waiver “would have undesirable consequences, as it would effectively serve only to relieve NRG of the financial consequences of its market commitments … and could encourage similarly risky bidding behavior that market participants seek to remedy after the fact through a waiver.”
Stepping in where others have failed, San Diego’s Sempra Energy on Monday announced a $9.45 billion cash deal to acquire bankrupt Energy Future Holdings and its 80% interest in Texas utility Oncor.
Sempra’s move short-circuited a looming battle between Berkshire Hathaway Energy and hedge fund Elliott Management, the largest holder of EFH bonds, which had opposed as too low BHE’s $9 billion all-cash offer in July. Elliott said it was working on a competing bid totaling $9.3 billion. (See PUCT Staff Welcomes Buffett’s Oncor Bid; Debtor Miffed.)
Elliott spokesperson Michael O’Looney said the investment fund is “supportive” of Sempra’s proposed transaction, “which provides substantially greater recoveries to all creditors of Energy Future than the proposed Berkshire transaction.”
Including debt, BHE’s bid valued Oncor at $18 billion, while Sempra’s values the utility at $18.8 billion.
Sempra CEO Debra Reed said the acquisition will “enhance our earnings beginning in 2018 and further expand our regulated earnings base, while serving as a platform for future growth in the Texas energy market and U.S. Gulf Coast region.”
Debt and Equity
The company said it expects to fund the transaction using a combination of its own debt and equity, third-party equity, and $3 billion of expected investment-grade debt at the reorganized EFH. Sempra will hold about a 60% equity ownership of EFH and projects the transaction to be completed in the first half of 2018.
BHE, which had said last week it would not increase its $9 billion all-cash offer for Oncor, announced Monday that EFH had terminated its proposed acquisition. Warren Buffet’s company is renowned for its fiscal discipline and avoids bidding wars.
The Nebraska-based company is eligible for a $270 million breakup fee, but it would have to be approved by the court overseeing EFH’s bankruptcy case in Wilmington, Del.
On late Friday, Berkshire said it had reached a settlement agreement resolving “all issues” with Public Utility Commission of Texas staff, the Texas Office of Public Utility Counsel, the Steering Committee of Cities Served by Oncor, Texas Industrial Energy Consumers and International Brotherhood of Electrical Workers Local 69.
Oncor CEO Bob Shapard praised Sempra as a “well-respected and experienced utility operator with a quality workforce and management team.”
“The announcement today is just another example of how our 3,900 employees have made Oncor one of the most sought-after companies in the energy sector today.”
At a previously scheduled bankruptcy court hearing Monday, EFH creditors expressed their support for the Sempra deal. Judge Christopher Sontchi set a Sept. 6 date for an expedited hearing on Sempra’s merger agreement. The deadline for filing objections is Aug. 31.
“This is a big change, clearly a change to the benefit of the estate and the creditors,” said Sontchi, thanking the parties for “freeing up his day.” The judge had scheduled up to eight hours of testimony and arguments on Elliott Management’s opposition to the Berkshire offer.
Oncor is the sixth largest transmission and distribution utility in the nation, serving more than 10 million Texans through more than 122,000 miles of wires and 3.4 million meters. It has been the subject of a tug-of-war since parent EFH, saddled with almost $50 billion in debt after poor bets on energy prices, declared bankruptcy in April 2014.
Dallas’ Hunt Consolidated and Florida-based NextEra Energy had separate bids fall apart in the face of the Texas PUC’s strict ring-fencing measures and demands that Oncor be run by a “truly independent” board with control over decisions on capital expenditures and operating expenses. (See NextEra-Oncor Deal Meets Third Denial.)
PUC Concerns
Although it was rejected by Elliott Management, Berkshire’s offer was received positively by PUC staff.
During the PUC’s open meeting Thursday, Commissioner Ken Anderson restated his insistence that Oncor be protected from incurring any additional debt from EFH’s bankruptcy proceeding. Anderson’s focus is on the billions in debt owed by Oncor stemming from the 2007 leveraged buyout of EFH’s predecessor, TXU.
That debt “was all incurred either in connection with the original [leveraged buyout] or refinancing the 2007 leveraged buyout,” Anderson said. “None of it ever was, nor can it be, an obligation, directly or indirectly, or legally implied of Oncor. None of either the principal or interest can go into rates.”
Anderson alleged that the suitors before BHE intended to use Oncor’s profits to pay off what he viewed as “imprudently incurred debt” by the utility’s holding company.
“The continued existence of any material amount of debt above Oncor will be a concern,” Anderson said. “One of the most important aspects is the cash flow generated out of Oncor must be protected. It needs to be available to Oncor’s management and to Oncor’s board to put it back into the business.”
The debt “is not Oncor’s problem. It is the problem of the commission now, but when the dust settles, I don’t want it to be the problem of either this commission or future commissions.”
Sempra has committed to support Oncor’s plan to invest $7.5 billion of capital over a five-year period to expand and reinforce its existing system.
New CEO
When the transaction is completed, Shapard will become executive chairman of the utility’s board of directors. Allen Nye, currently the utility’s general counsel, will succeed Shapard as CEO. Both have been asked to serve on the board, which will consist of 13 directors, including seven independent directors from Texas, two from existing equity holders and two from the new Sempra-led holding company.
The transaction is subject to customary closing conditions, including the approval of the PUC, FERC, the bankruptcy court and antitrust regulators at the U.S. Justice Department.
“It is important for Oncor to remain financially strong,” Sempra’s Reed said. “Our proposal will help bring a satisfactory resolution to Energy Future’s bankruptcy case, keep Oncor financially strong and protect Oncor customers, while addressing the needs of Texas regulators, creditors and the U.S. bankruptcy court.”
The deal would allow Sempra to regain a foothold in Texas, where it once owned and operated 10 power plants and currently maintains a 200-person office in Houston to support marketing and development activities. A Fortune 500 corporation that includes San Diego Gas & Electric and Southern California Gas, Sempra had 2016 revenues of more than $10 billion.
Sempra’s announcement was not a complete surprise. Word began leaking out last week that a mystery bidder had emerged to take on BHE’s offer. During a bankruptcy hearing Friday, legal counsel for Elliott identified the new competitor for Oncor as “a large investment-grade utility.”
Elliott’s representative also told the court that EFH was considering pursuing talks with the new competitor. EFH’s board met Friday and Sunday before accepting Sempra’s offer.
FERC last week approved GridLiance West’s acquisition of Valley Electric Association’s 230-kV transmission network in a deal valued at about $200 million (EC17-49).
The commission also granted GridLiance’s request for incentive rate treatment for operating the network. And while FERC accepted the company’s formula rate template for filing, those rates will be subject to a further evidentiary hearing before a settlement judge to determine the reasonableness of proposed rate inputs, return on equity and income tax allowance (ER17-706).
The decision to approve the transaction came despite objections from some CAISO members who contended that the transaction would result in increased in costs to ISO stakeholders.
GridLiance will be taking over 164 miles of 230-kV lines linking Valley Electric’s base in Pahrump, Nev., with both Las Vegas and the Mead substation — a major delivery point for power wheeled into California — as well as substations along the length of the system. The sale will earn Valley Electric 2.4 times its investment in the system, which significantly increased in value when the cooperative joined the ISO in 2013.
In a filing with FERC, GridLiance said that incorporating its revenue requirement into CAISO’s High Voltage Access Charge will increase that charge by about 0.48%, or $10.8 million. The company attributed the rate bump to the differing business structures of Valley Electric, which is a nonprofit rural electric cooperative, and GridLiance, a for-profit startup that will incur greater costs for overhead, administrative costs and taxes.
GridLiance argued that the increased cost would be offset by the benefit of having the transmission network of a well-funded transmission company that would add competition to the CAISO market and be focused on expansion and enhancement of the ISO transmission system.
The Transmission Agency of Northern California (TANC) contended that, although GridLiance had promised not to recover through rates any acquisition premium paid for the Valley Electric network, the $10.8 million increase in the ISO’s transmission revenue requirement (TRR) constituted such a premium. TANC noted that the increase represented a near doubling of the TRR for the network — without GridLiance having incurred any costs for improvements or modifications. The agency also argued that the transaction would not result in any “quantifiable or non-quantifiable” benefits that would offset the increased costs.
GridLiance West’s acquisition of Valley Electric Association’s 230-kV will provide the company with strategic access to the CAISO market. | Valley Electric Association
Southern California Edison (SCE) contended that the initial revenue requirement included in GridLiance’s proposed formula rate may be “unjust and unreasonable” and possibly included “improper and unsubstantiated costs and expenses.” SCE argued that the commission could not decide about the acquisition without fully vetting the impact of GridLiance’s formula rate filing.
The “Six Cities” utilities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside raised many of the same concerns, asking why the revenue requirement for the transmission facilities will increase just because of a transfer of ownership.
FERC came down firmly on the side of GridLiance, saying the 0.48% increase in the access charge was “not unexpected” given the company’s capital structure, tax obligations and “need to earn a return.” The commission also determined that GridLiance had presented evidence that increased costs would result in offsetting benefits.
“GridLiance West represents that it intends to develop needed upgrades and important transmission projects that will improve system reliability and increase transmission capacity to meet growing demand for renewable resources, including, and in particular, exports out of the Valley Electric area,” the commission said.
Valley Electric said that it would be unable to perform those necessary upgrades in a timely manner.
“Due to its singular focus on developing and owning transmission facilities, GridLiance West will not face the difficult decisions Valley Electric has faced in allocating its limited financial resources among the various infrastructure development needs within its service territory,” the commission said.
FERC last week granted Grand River Dam Authority’s (GRDA) request for a permanent 2-foot increase in the reservoir level of the 105-MW Pensacola Project in northeastern Oklahoma, despite opposition from a nearby Native American tribe (Project Nos. 1494-437, 1494-441).
The Miami Tribe charged that FERC had not lived up to its obligations under Section 106 of the National Historic Preservation Act, which requires federal agencies to conduct a review to determine how a proposed project may affect historic properties and to seek ways to avoid, minimize or mitigate any “adverse effects.”
Overhead of Pensacola Dam complex including auxiliary spillways | courtesy of the U.S. Geological Survey
The tribe asserted the commission never engaged in a Section 106 review with respect to tribal cultural properties in and around the hydropower project, which includes a 5,950-foot-long, 147-foot-high dam and the 46,500-acre Grand Lake reservoir. The review would have included gathering information from tribes, identifying historic properties of relevance to the tribes and assessing the effects that the project has already had on historic tribal properties.
FERC disagreed, saying the Miami Tribe relied on assertions made by Oklahoma agencies “that have since been revised,” and pointed out that the state agencies did not object to the commission’s finding that the reservoir-level change would not affect historic properties.
| Grand River Dam Authority
GRDA, an SPP member, last year requested maintaining the reservoir level at the dam on the Grand River at 743 feet between Aug. 16 and Sept. 15, 2 feet above current levels. It also requested a 742-foot level between Sept. 16 and Oct. 31, 1 foot above current levels. The company proposed returning to the project’s existing surface elevation or “rule curve” for the remainder of the calendar year.
The project’s dedicated flood storage is listed at 745 to 755 feet. When reservoir levels are within the flood pool, the U.S. Army Corp of Engineers can direct releases from the dam.
FERC last week rejected a CAISO proposal to extend the life of a program designed to protect some renewable energy resources from being assessed uplift costs associated with their variable output (ER17-1337).
The ISO established the Participating Intermittent Resource Program (PIRP) in 2014 as part of enhancements to its real-time market under FERC Order 764. PIRP provided older variable energy resources (VERs) a three-year transition period in which to acquire the capability to respond to dispatch instructions, during which they would avoid being assessed for startup costs for conventional generation needed to respond to uninstructed, intermittent output.
The program also accommodated renewable resources that needed additional time to renegotiate long-term power purchase agreements that expressly prohibited them from responding to real-time price signals.
CAISO earlier this year proposed to extend PIRP for an additional year until Apr. 30, 2018, contending that several resources operating under the program required more time for the transition. The ISO contended that the nine resources using the program had received a net benefit of $5.6 million between 2014 and 2016, an amount that was not expected to increase significantly with a one-year extension. The cost of extending the measure would continue to be allocated across all ISO scheduling coordinators.
In denying the extension, FERC said that “CAISO has not argued that the three-year transition period was an unreasonable time frame, or that circumstances have changed since the commission originally accepted” PIRP. The commission also noted that extending the program would expose market participants to additional uplift charges for another year while not guaranteeing that the protected resources would resolve their challenges during that time.
“Further, CAISO does not assert and the record does not indicate that allowing the protective measures to expire on April 30, 2017, would pose a risk to reliability, or that the relevant VERs would suffer significant financial losses as a result of their expiration,” the commission said.
The commission also agreed with Pacific Gas and Electric that allowing PIRP to remain in place would not give the relevant resources an “economic incentive” to respond to CAISO dispatch signals.
“CAISO itself has highlighted the need for resources to respond more quickly to CAISO dispatch instructions to curtail generation during oversupply conditions,” the commission said.
Calpine announced Friday it has agreed to be acquired by Energy Capital Partners and other investors for $5.6 billion in cash, or $15.25/share, a 51% premium to Calpine’s share price when news of a potential deal became public in May, and a 13% bump from Thursday’s close.
Energy Capital Partners, a private investment firm, is being joined by a group of investors led by the Canada Pension Plan Investment Board, which said it will invest $750 million, and Access Industries, a privately held company with investments in a wide variety of industries and companies, including Warner Music Group, Houston-based oil and natural gas producer EP Energy, and Russia-based aluminum manufacturer UC RUSAL.
The investors will be purchasing Calpine’s 26-GW fleet of 80 power plants in operation or under construction, the largest fleet of natural gas generators in the U.S. Its assets are concentrated in California (5,500 MW of natural gas and 725 MW of geothermal); Texas (13 combined cycle plants totaling 9,000 MW) and the East (31 plants totaling 9,400 MW in 14 states and Canada, most of them in PJM and ISO-NE).
In addition to its generation assets, Calpine also has two retail businesses — Calpine Energy Solutions and Champion Energy — which operate in 25 states, Canada and Mexico.
| M.J. Bradley & Associates (2017); “Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States”
M.J. Bradley & Associates ranked Calpine as the nation’s 10th largest power producer in 2015. Calpine claims to be the top-ranked generator in gas-fired capacity in Texas, with a No. 2 ranking in California and No. 3 rankings in the Mid-Atlantic and New England states.
Undervalued
During a call to discuss second-quarter results before the deal was announced, CEO Thad Hill explained the rationale for going private, saying “the public equity markets have undervalued our business and underappreciated our strong track record of executing on our financial commitments and our stable cash flows.”
Hill, who became COO in 2010 was promoted to CEO in 2014, said the acquisition will not change the company’s operations. The company will maintain its headquarters in Houston and its current management team, he said.
The sale will allow the company to “continue to strengthen our wholesale power generation footprint, while benefiting from ECP’s support, industry expertise and long-term investment horizon,” Hill said in a statement.
| Calpine
ECP partner Tyler Reeder confirmed that the deal would not result in operational changes, saying that the investors “see significant value in Calpine’s operational excellence and strong and stable cash flows, and have been impressed by the company’s exceptional leadership and talented employees.”
“We do not intend to make any changes to the company’s financial policy or previously announced $2.7 billion deleveraging plan,” he added, referring to plans to pay off the debt in full by 2019.
Including debt, The Wall Street Journal reported, the deal’s enterprise value is $17 billion.
The deal allows Calpine a 45-day “go-shop” period to seek a higher offer. The company would have to pay the ECP group a $142 million termination fee for canceling the deal. The fee would be reduced to $65 million if Calpine terminates the agreement within 106 days.
“We don’t think it is likely there is a topping bid,” Greg Gordon, an analyst at Evercore ISI, wrote in a research note, according to Bloomberg. “It was probably very hard to pull together an equity consortium for this size of a deal and it was a competitive process.”
The acquisition is subject to approval by Calpine stockholders, antitrust regulators, FERC and state regulators, including those in New York and Texas, the company said. Closing is targeted for the first quarter of 2018.
Seesaw Ride for Investors
York Energy Center | Calpine
Founded in 1984, Calpine went public in 1996 and grew steadily over the next several years before falling into bankruptcy in 2005. It moved its headquarters from California to Houston after exiting bankruptcy in 2008.
Like other independent power producers, Calpine has been pinched by low power prices and competition from renewables.
NRG Energy, which lost $626 million last quarter, is planning to sell as much as $4 billion of its assets, and last month it ordered an undisclosed number of layoffs. Dynegy, which lost $296 million in the second quarter, is reportedly considering an acquisition by Vistra Energy. (See Report: Vistra Energy Suggests Takeover of Dynegy.)
Calpine’s 2016 profit of $92 million was a 60% drop from 2015. It reported a second-quarter loss of $216 million after losing $56 million in the first quarter. Rising gas prices have resulted in reduced capacity factors for the company’s non-peaker plants, falling to an average of 43.6% in the first six months of the year from 48.8% a year earlier.
After peaking at almost $25/share in late 2014, Calpine’s share prices fell as low as $10 in April before news of a potential deal. Shares closed Friday at $14.92.
Energy Capital’s Plans
Based on its history, ECP may not keep Calpine for very long.
In 2015, it sold EquiPower — a company it created five years earlier to oversee a portfolio of fossil generators in the eastern U.S. — to Dynegy. In 2008, two years after acquiring it, ECP sold FirstLight Power Resources, a 1,440-MW portfolio of mostly hydro generation, to a subsidiary of GDF SUEZ, now ENGIE.
The firm also helped Dynegy finance its $3.3 billion acquisition of 17 U.S. power plants, selling its stake to Dynegy last year for $750 million. The company was Dynegy’s largest stakeholder as of June, according to Bloomberg.
ECP’s current holdings include Wheelabrator Technologies, which generates power from municipal solid waste and other renewable waste fuels.
FERC last week asked for additional comments on the rule it proposed in November that all newly interconnecting generators provide primary frequency response.
The Notice of Proposed Rulemaking, which reflected both reliability concerns and the technological advances of renewable generators, proposed revising the pro forma Large Generator Interconnection Agreement (LGIA) and Small Generator Interconnection Agreement (SGIA). (See FERC Proposes Frequency Response Requirements for Renewables.)
On Friday, the commission issued a notice requesting supplemental comments on electric storage and small generators (RM16-6).
The commission said it was prompted by the Energy Storage Association (ESA) and other commenters who said that the NOPR failed to address storage’s “unique technical attributes” and could discriminate against them.
ESA said that the proposed use of nameplate capacity as the basis for primary frequency response service and the fact that electric storage resources can operate at the full range of their capacity — without a minimum set point — would require them to provide a “greater magnitude of [primary frequency response] service than traditional generating facilities.”
“In light of these concerns, the commission seeks additional information to better understand the performance characteristics and limitations of electric storage resources, possible ramifications of the proposed primary frequency response requirements on electric storage resources, and what changes, if any, are needed to address the issues raised by ESA and others,” the commission said.
FERC also asked for more information on commenters’ concerns that small generating facilities could face disproportionate costs in providing frequency response.
Commenters including the Sierra Club, the Sustainable FERC Project and the National Rural Electric Cooperative Association said that the NOPR failed to prove the commission’s conclusion that “small generating facilities are capable of installing and enabling governors at low cost in a manner comparable to large generating facilities.”
Comments will be due 21 days after publication of the notice in the Federal Register.
Connecticut regulator John W. “Jack” Betkoski III, the new president of the National Association of Regulatory Utility Commissioners, last week called for more transparency at the New England Power Pool and said he plans to focus his NARUC tenure on the “water-energy nexus.”
Betkoski, vice chairman of the Connecticut Public Utilities Regulatory Authority, had been serving as NARUC’s first vice president before assuming the presidency on Aug. 14 from former Pennsylvania regulator — now FERC Commissioner — Robert Powelson. He will complete Powelson’s term and in November begin a full 12-month term.
In an interview, Betkoski told RTO Insider about his priorities at NARUC.
“You usually roll [priorities] out in November, but I’m probably going to [do] something with the whole water-energy nexus,” he said. “That’s certainly very important to what we do as regulators. You need both water for energy and energy for water. It’s something that we as regulators could highlight. I’ve always felt very passionate about the water cases that I’ve been involved in.”
NARUC committees set up to explore the issue would be divided equally between electric and water utility regulation, he added.
“Thank goodness that we have iPads and computers and everything else, because I can certainly fill my responsibilities here in Connecticut with my dockets but also be doing the great work we have to do with the national organization,” Betkoski said. “There’s so much going on, and the whole re-composition of [a quorum] at FERC, that’s going to be something that in my new role we’ll be getting reacclimated to, a fully staffed FERC organization within the next couple months.”
Betkoski declined to comment on dockets currently before PURA, on the state-federal tensions that prompted a FERC technical conference in May or on PURA’s role under Gov. Dannel Malloy’s executive order to assess the economic viability of Dominion Energy’s Millstone nuclear plant. “Katie is the lead commissioner on that joint proceeding,” he said, referring to PURA Chair Katie Dykes. (See related story, Commenters Seek Broader Response on Millstone, Renewables.)
Betkoski also demurred on elaborating on his plans for NARUC and the water theme: “It’s not even a week since I took over, so it’s really transitional right now.”
NEPOOL Transparency
Betkoski was surprised to learn last year that most stakeholder meetings of the New England Power Pool, which advises ISO-NE, are closed to the public and the press. Most meetings of the other six RTOs and ISOs are open.
NEPOOL is “doing something that impacts ratepayers, and anything like that should be as transparent as possible,” Betkoski said. “I know that’s certainly the way we operate here. I’ve been a commissioner for 20 years, and certainly I encourage people to come to public hearings and certainly have never kicked journalists out of public hearings, and I think the same should hold true for them.”
Jack Betkoski talks about storm-related outages on a TV program in November 2013 | Connecticut Public Utilities Regulatory Authority
If a discussion concerns proprietary information, the regulatory agency can go into executive session, but other than that the meetings should be open, he said.
Betkoski will be formally installed as president in November at NARUC’s Annual Meeting and Educational Conference in Baltimore. Wisconsin Public Service Commission Chair Ellen Nowak will also be formally installed as first vice president in Baltimore, while the second vice president position she is vacating will be filled at the same meeting.
A Democrat from Beacon Falls, Betkoski has served on Connecticut’s utility regulatory authority since 1997, when it was known as the Department of Public Utility Control. Malloy appointed Betkoski to the newly created PURA in 2011 and reappointed him to a four-year term that began in 2015. He is a past president of the New England Conference of Public Utilities Commissioners.
He has served on NARUC’s executive committee since 2012 and is currently chairman of the Connecticut Water Planning Council and a member of the American Water Works Association Research Foundation’s Public Council on Drinking Water Research. He previously served as a member of the EPA National Drinking Water Advisory Council’s Water Security Working Group.
The department and other market participants recently submitted comments on CAISO’s straw proposal for its Commitment Cost and Default Energy Bid Enhancements (CCDEBE) initiative. The proposal is designed to more accurately reflect unit commitment costs and overhaul the way the ISO calculates the default energy bid (DEB), which replaces bids of units found to have market power. (See CAISO Developing New Bidding Rules.)
The Monitor said it continues to recommend that CAISO split the proposal into parts and that more time is needed to develop dynamic mitigation. “The development and implementation of dynamic mitigation of commitments costs is relatively complex and the ISO has made very limited progress on developing technical details of an approach for actually implementing this,” it said.
“Given the flaws and lack of detail in the ISO’s commitment cost mitigation design,” the Monitor does not support a proposal to raise the caps on market-based commitment cost bids above the current level of 125%.
One of CAISO’s rationale for the new program is incentivizing flexible resources. The grid operator says that overly constrained supply offers discourage participation by some resources in the ISO and the Western Energy Imbalance Market (EIM), where the changes would also apply.
There are three power suppliers subject to the DEB: Arizona Public Service and Berkshire Hathaway’s PacifiCorp and NV Energy. In comments filed Aug. 15, NVE said it supports increasing the flexibility of supply bids and reforming the DEB methodology “to ensure appropriate recovery of actual supply costs.”
The Western Power Trading Forum said it supports the concept of the revised proposal but asked for additional information on the frequency of mitigation. The group supports CAISO’s proposed hourly minimum load offers, market-based commitment costs subject to mitigation and improved estimates of commitment costs. It also offered suggestions on details of the market design.
Pacific Gas and Electric said it supports part of the proposal but wanted additional detail before it would endorse the changes. “PG&E continues to have concerns about committing to move forward with a dynamic mitigation design while many questions remain regarding design details, feasibility and cost,” the company said. It said that more analysis is needed and that the dynamic mitigation should be split off from the rest of the CCDEBE proposal.
CAISO has acknowledged that its time schedule has been rapid since the original straw proposal was issued on June 30, but it says it is aiming for approval at the Nov. 1 Board of Governors meeting. The ISO said that some parties are anxious to have the new rules approved.
After originally setting an Aug. 10 deadline for comments — only eight days after the revised straw proposal was posted — CAISO extended the comment period to Aug. 15.
The ISO has made several changes to the package based on stakeholder input. The initiative has other market adjustments, including alterations to the use of gas indices and rules to allow cost-based energy offers above $1,000/MWh, in compliance with FERC’s November 2016 Order 831.
Some stakeholders thought the EIM Governing Body should sign off on the changes, but CAISO declined, saying it would offer only an advisory vote to the body since the initiative applies across all CAISO markets.
CAISO’s proposal to provide transmission revenue to balancing authority areas (BAAs) that wheel power between other BAAs received a wary response from Western Energy Imbalance Market (EIM) stakeholders last week.
Currently BAAs that wheel power are only paid if the system is congested.
The compensation change is part of a package of refinements that CAISO is developing, including fundamental changes to the way transmission is treated in the developing market. EIM entities filed comments on the proposals Thursday.
Powerex Sells Power from BC Hydro Plants Such as the Revelstoke Dam
Wheeling is on the increase as the EIM grows and more regions are added. When Powerex is integrated in April 2018, for example, Puget Sound Energy will be positioned to wheel power from British Columbia to the south. Powerex markets a BC Hydro portfolio of about 17,000 MW of generating capacity, about 12,000 MW of which is hydro.
Powerex said it supports the compensation proposal and wants CAISO to adopt a net wheeling charge on all EIM transactions to pay for it. The Province-owned company said that such transactions represent a significant portion of import and export volumes, “which suggests that such transactions may be critical to the EIM’s ability to generate benefits.”
But the company said that any wheeling charge should not impede economic dispatch and reduce EIM benefits. It is “critical that any such charge be designed in a manner that ensures that the incremental hurdle rate that is created is as small as possible. Such transactions may be critical to the EIM’s ability to generate benefits,” it said.
PacifiCorp, which has been operating in the EIM since the market went live in November 2014, said it has concerns about the proposal, arguing that “it is too early to understand if there is truly a market problem to be solved.” The company said CAISO should wait until after Portland General Electric, Powerex and Idaho Power are integrated to get a better understanding of how resources will be scheduled in the expanding market. PacifiCorp owns about 10,600 MW, including about 2,500 MW of wind, and plans to retire 3,650 MW of coal-fired capacity by 2036.
PacifiCorp’s Hunter Coal-Fired Plant Near Castle Dale, Utah
It is possible that the increased wheeling over the past nine months was related to “anomalies” such as excess hydro or the outage at the Aliso Canyon natural gas storage facility, the Berkshire Hathaway-owned company said.
“PacifiCorp recommends that the initiative be postponed and continue to be monitored so that new entrants can make informed comments that truly reflect transfers across their systems,” the company said.
The company also noted that CAISO had proposed market changes to accommodate the integration of Powerex, but that most of the additional functionality would not apply to PacifiCorp. The company believes Powerex will not be required to participate in security-constrained economic dispatch in its BAA like other EIM entities.
CAISO has two plans for the charges: an added “hurdle rate” into transmission costs that is distributed to participants in the transaction through a congestion offset; and an “ex-post” payment to entities facilitating the transmission that would be collected directly from the source and sink BAAs.
Monitor, Public Interest Groups Oppose
CAISO’s Department of Market Monitoring said both approaches would cause inefficiencies. The charge appears to be a proxy for other EIM benefits, the department said, and is “overly simplistic” for cost allocation. “These inefficiencies may result from a per-megawatt-hour fixed cost recovery approach influencing bidding behavior, or more directly through the hurdle rate, which may lead to inefficient dispatch of EIM resources,” the Monitor said.
A collection of public interest organizations also opposed the proposal, saying it could reduce overall EIM benefits and possibly reduce investment. The group includes Western Resource Advocates, the Natural Resources Defense Council and Western Grid Group.
“Not only will these schemes unnecessarily complicate the EIM’s market design, thereby undermining its benefits, but they appear to be a solution in search of a problem, given that all EIM BAAs are importing and exporting more than they are facilitating wheeling,” they said.
They also said that CAISO should not focus on minor inequities in the EIM because it distracts stakeholders from the benefits the market brings. If the ISO does pursue it, the groups support the ex-post payment approach, saying it is least disruptive to the market and would adapt well to a changing EIM.
Seattle City Light voiced strong opposition, saying that a more robust stakeholder review is needed before making such a change, noting that CAISO has not identified free riders or cost shifts. The municipal utility owns 2,000 MW of hydro and transacts in the EIM.
“City Light is particularly concerned with the proposal to address a benefits-related issue by implementing an additional cost to EIM entities. The addition of a new cost is an imprecise tool to address a concern over inequitable distribution of benefits,” the publicly owned utility said.
Portland General Electric in its comments said it “is not convinced that this initiative has been appropriately scoped, or that the market design, policy and regulatory considerations have been fully considered, and therefore does not believe it is prudent at this time to move forward with either of the ISO’s policy recommendations.”
Southern California Edison (SCE) also opposed the changes, saying that participating in the EIM does not guarantee uniform benefits to all entities and CAISO.
“While SCE understands that examining the actual benefits and costs after the fact rather than relying on estimates prior to EIM is a good practice, SCE believes that in this case, the data support the current practice and policy and that no changes are warranted,” the company said.
Arizona Public Service supported the proposal but said it should apply equally across the EIM and not offset the market’s benefits.
Most stakeholders support CAISO’s decision to eliminate from the package of market rule changes a plan to allow third-party transmission owners to participate in the EIM. There was lackluster interest from current EIM entities and it was thought the provisions would be little-used. (See CAISO Drops EIM Third-Party Transmission Plan.)
The ISO Board of Governors is due to review the package of changes at its Nov. 1 meeting.
