California electricity sellers are cautiously supportive of CAISO’s proposal to permanently assume authority to limit output from gas-fired generators as an emergency response to possible limitations on gas deliveries.
But the ISO’s Department of Market Monitoring (DMM) said the grid operator has not fully justified its gas-electric coordination straw proposal and concerns need to be addressed before it would recommend approval by the Board of Governors or FERC.
CAISO last month proposed imposing the gas-electric coordination measures across both the ISO and the Western Energy Imbalance Market (EIM). (See Plan Would Apply Aliso Canyon Measures Across CAISO, EIM.) The curtailments previously were limited to the area in Southern California affected by the massive gas escape from Aliso Canyon, which since October 2015 has been subject to ongoing withdrawal restrictions.
Southern California Gas’ Aliso Canyon Storage Facility | California Governor’s Office of Emergency Services
“The draft final proposal does not address many of the key concerns from the straw proposal highlighted by DMM,” the Monitor said. While the ISO has said the constraints have been effective, it “has not provided much analysis or explanation as to how well the constraints worked.”
The department said its support of gas price scalars used to distinguish resources affected by the gas limitations from the rest of the ISO market areas is dependent on the results of its analysis as to whether they are warranted. The scalars would be applied to the next-day gas index published the morning of the day-ahead market run to calculate cost estimates.
Power sellers are evaluating the effect of the measures, which target not only Aliso Canyon but other storage and delivery constraints on the system. Natural gas can be diverted to address heating needs, as it was over four days in January when CAISO constrained gas plant output.
In comments filed with CAISO, Portland General Electric (PGE) — which will join the EIM in October — said “this administrative measure needs to be characterized in the filing as a last-resort option, deployable for the specific purpose of maintaining system reliability during outlier events.” Market-based solutions are preferable, and the utility requested that the ISO work on needed price formation and bidding enhancements.
SCE’s Mountainview Natural Gas-Fired Plant, Redlands | Edison International
PGE asked what would be the likely effect of the policy on LMPs, as well as whether it would undermine market participants’ ability to manage risk. PGE and Pacific Gas and Electric both wondered what exact events or evaluations would cause the constraints to kick in.
The Western Power Trading Forum said: “The ISO’s explanation as to why extending the Aliso Canyon measures to the entire footprint would help to protect reliability under certain extreme conditions is reasonable; however, it should be noted that no other ISO has such authority to disrupt the market in such a way, and that under the EIM, the individual balancing authorities remain responsible for ensuring the reliability of their system.” The group said its support is contingent on the scalars remaining at the current place and across the entire EIM footprint.
The California Public Utilities Commission is also exploring whether to shut down Aliso Canyon entirely. (See Study to Weigh Aliso Canyon Shutdown.) Residents near the facility still complain about health problems they say are associated with the leak, putting more pressure on elected officials and regulators to respond to the local impact.
A federal appeals court Friday slapped down FERC for overstepping its authority in a ruling forcing PJM to abandon a stakeholder compromise on market power rules.
The D.C. Circuit Court of Appeals decision remanding FERC’s order eliminates portions of PJM’s minimum offer price rule that have been in place since 2013 and orders the commission to review its decisions on the topic (15-1452).
The court determined that FERC exceeded its “passive and reactive role” under Section 205 of the Federal Power Act when it denied a 2012 proposal by PJM to revise its MOPR provisions but suggested additional revisions that it would accept.
Kavanaugh | Harvard Law School
Section 205 requires FERC to accept proposed rate changes as long as they are just and reasonable, allowing the commission to suggest only “minor” changes, the court said in an opinion written by Judge Brett Kavanaugh. “Section 205 does not allow FERC to suggest modifications that result in an entirely different rate design than the utility’s original proposal or the utility’s prior rate scheme.”
PJM’s proposal would have replaced the unit-specific MOPR exemption with two new ones and extended the mitigation period from one to three years before a unit could bid below the price floor. The change was prompted by generators’ concerns that the unit-specific review, which allowed units to prove confidentially to PJM that its costs were below the required minimum offer, lacked transparency and allowed below-cost bids.
In exchange for eliminating the exemption, load-serving entities won an agreement for two new exemptions: a competitive-entry exemption for units that are unsubsidized or subsidized through a non-discriminatory, state-sponsored procurement process and a self-supply exemption for units intended to meet a portion of an LSE’s needs.
Widely Supported
The compromise proposal was widely supported by PJM stakeholders — the first time that a significant MOPR revision had won a two-thirds sector-weighted vote, the court noted.
Nevertheless, FERC rejected the proposal in May 2013, saying it discouraged new entry because the exemptions were too narrow and the mitigation period was too long (ER13-535). However, it indicated it would accept the proposal if the unit-specific review were retained and the mitigation period remained unchanged. PJM agreed in a compliance filing adopting FERC’s changes. (See FERC OKs PJM MOPR Exemptions; Rejects End to Unit-Specific Review.)
A dozen stakeholders requested rehearing: NRG Energy, FirstEnergy, the PJM Power Providers Group (P3), Calpine, Exelon, PPL, Public Service Enterprise Group, the Illinois Commerce Commission and consumer advocates from New Jersey, Maryland, Delaware and D.C. (See FERC won’t Rehear PJM MOPR Ruling.)
When FERC declined rehearing, NRG Power Marketing, GenOn Energy Management and P3 petitioned the D.C. Circuit to review the order. On Friday, the court agreed that FERC “exceeded its authority” by suggesting the modifications that it would approve, even though PJM agreed to them, because that proposed an “entirely new rate scheme.”
Compromise ‘Eviscerated’
Additionally, the court said FERC “largely eviscerated” the compromise that had gotten the original proposal through PJM’s stakeholder process. The court noted that PJM asked FERC to approve the filing “not as a list of discrete Tariff changes, but as a hard-fought compromise package.”
“PJM’s proposal would have narrowed the availability of exemptions to the price floor for some generators that, in the view of some of PJM’s stakeholders, posed a high risk of price suppression,” Kavanaugh wrote. “But FERC’s proposed modifications went in the opposite direction. FERC’s modifications expanded the exemptions by layering the two new exemptions on top of unit-specific review and by exempting certain new generators from the price floor after one year instead of after three years. Indeed, FERC’s modifications expanded the scope of the exemptions not just beyond PJM’s original filing, but beyond the scope of the exemptions as they had stood before PJM’s filing.
“Because of FERC’s modifications, some generators can now claim exemptions from the price floor even if they cannot demonstrate that their costs fall below the price floor,” he continued. “In other words, due to FERC’s modifications, PJM’s previous case-by-case methodology no longer controls.”
PJM Agreement Irrelevant
The fact that PJM agreed to FERC’s suggestions “does not cure the harms” to its stakeholders, the court said.
“When FERC imposes an entirely new rate scheme in response to a utility’s proposal, the utility’s customers do not have adequate notice of the proposed rate changes or an adequate opportunity to comment on the proposed changes,” it said. “Generators and load-serving entities had an opportunity to comment on the original compromise proposal submitted by PJM. But they did not have an opportunity to comment on FERC’s modifications before FERC issued its decision.”
NRG was pleased with the ruling.
“This decision effectively calls for a rewrite of market rules that effectively allowed new entrants to distort the energy and capacity markets by subsiding new entry,” spokesman David Gaier said. “We’re hopeful that any new rules will level the playing field and support fair and equitable electricity markets for all generating resources.”
CAISO must address fundamental flaws in its proposal to allow third-party transmission providers to make unused capacity available to the Western Energy Imbalance Market (EIM), according to the ISO’s internal Monitor and market participants.
The Department of Market Monitoring said the ISO must consider that the rule change could incentivize third-party transmission providers to withhold transfer capacity from the EIM in order to increase their own revenues from congestion.
CAISO proposed allowing third-party transmission Into The EIM | Berkshire Hathaway Energy
The Monitor and imbalance market participants filed comments with CAISO on a combined set of EIM-related proposals, which also include measures to address monetary charges related to bilateral schedule changes and allow EIM balancing authority areas that wheel power to share in revenue from energy transfers. (See CAISO Proposes Consolidated EIM Changes.)
‘Self-defeating’
CAISO EIM as of June 1, 2017 | CAISO
Current EIM rules allow members to collect congestion revenue from the market through an offset. Under the ISO’s proposal, that benefit would be extended to third parties that offer their unused capacity to the market in order to increase transfer capacity between imbalance market areas.
But the Monitor pointed out that the change could enable a third-party transmission owner to offer transmission for EIM transfers and then reduce the quantity available, creating congestion revenue for its own benefit. The Monitor recommended that the ISO restrict transmission providers’ ability to reduce capacity once offered.
Compared with other imbalance market entities, “third-party transmission providers may be less likely to have ownership interest in generation resources which would be impacted by market prices,” the Monitor said.
The Bonneville Power Administration argued that the proposal is “self-defeating” because transmission providers would be decreasing their own congestion revenues. BPA said that “in order to incent third-party transmission to be made available to the EIM, the CAISO needs to find a compensation method that fairly compensates the third-party contributor even when no congestion exists.”
Pacific Gas and Electric questioned whether the proposal creates a disincentive for non-EIM entities to participate more fully in the market. “PG&E would also be interested in the CAISO sharing any studies or insight it has on what transmission transfer capability (i.e., what paths) it anticipates making available via this change,” the utility said.
PacifiCorp said “the proposal should explicitly address how market power potential is addressed in light of the possibility of transmission capacity withholding where the entity contributing the transmission may also be a transmission provider or path operator with the ability to constrain dynamic capability and/or all flows on an EIM transfer tie.” The company also raised questions about market transparency, saying there are issues about validating congestion rent payments.
Seams Scheduling Mismatch
CAISO is also exploring whether it can use its current “wheeling bid” function to manage bilateral schedule changes originating within or moving across the imbalance market footprint. Under current EIM practice, such schedule changes made after the submission of hourly base schedules are exposed to real-time imbalance settlement payments that are not known ahead of time.
Adding wheel-out functionality would help market participants avoid imbalance charges by enabling them to pair their scheduled imports with an EIM export closer to the time of delivery. It would also allow for an EIM generating resource to pair its output with an export from the EIM area. Currently there is no functionality to support an import bid that sinks into the EIM area because non-participating load does not bid into the real-time market, CAISO said.
BPA said the proposal does not address a major seams issue between the EIM and Western bilateral markets because load inside the imbalance market is unable to make schedule changes after the window has closed for hourly base schedules.
“That window is both well ahead of the [Western Electricity Coordinating Council] standard for changes to hourly schedules and also doesn’t allow for loads to benefit from 15-minute schedules as they are implemented throughout most of WECC,” BPA said.
Imbalance market loads are precluded from adjusting schedules to reflect changes in load or generation and often have to choose between minimizing a scheduling error or being exposed to unknown prices, the result of which may be an actual increase in imbalance in the EIM, BPA said. The power agency said it “encourages the CAISO to develop a mechanism for parties to make scheduling adjustments for bilateral imports into an EIM entity consistent with standard bilateral scheduling practices.”
Wheeling Changes
Market participants are also analyzing CAISO’s proposal to allow balancing authority areas through which power is wheeled to share in revenue when energy transfers occur. EIM energy transfers through balancing areas are exempt from wheeling charges, and the market rule changes would allow the source, wheel-through and sink balancing areas to share in revenue recovery.
PG&E said that although it is “open to examining the allocation of wheeling benefits holistically at some point, this change would seem to create a somewhat ad hoc form of rate pancaking not aligned with the current imbalance market structure and principles.”
The Monitor said it would examine the wheeling charge and “intends to closely follow the policy development in this area, with the goal of maintaining efficient market design as the ISO seeks to address concerns of equity.”
CAISO last month published an issue paper describing the three EIM modifications and expects to submit the proposals to the EIM Governing Body in October and the ISO Board of Governors in November.
SACRAMENTO, Calif. — California utilities and business groups are opposing a proposed state law that would increase the amount of publicly available data about electricity consumers, saying it presents a major risk to physical grid security.
But environmental groups and others support the energy data transparency bill (SB 356) because it would allow customers to better manage their data and provide them more visibility into grid operations, reducing barriers to participation in energy efficiency and other programs.
The State Assembly Committee on Utilities and Energy on Wednesday passed the Democrat-sponsored bill along party lines. Committee members added amendments that require customer permission to release information and direct the California Public Utilities Commission to determine exactly what information should be released.
The bill, approved by the State Senate in May in a 25-13 vote, will move to the Assembly Appropriations Committee before going back to the Senate for another vote.
The bill’s sponsor defended the bill, which has also drawn opposition from business and public interest groups representing Latinos and African-Americans.
“The fact that some folks assert these privacy issues — whether it is a fact or an assertion are two different things,” Sen. Nancy Skinner (D) said during the hearing. The bill as amended allows the PUC to factor in security and privacy when evaluating what data are to be made public, she said. Skinner added that the measure would “clearly communicate” to the PUC that the legislature supports usage of anonymized data to enable a more efficient and lower-cost electricity grid.
Several technology and environmental groups support the bill, saying it would point to areas on the system where distributed energy resources or clean energy technology could be deployed.
The bill requires the PUC to make capacity, distribution infrastructure and pricing data available to the public in a machine-readable format on the Internet by Jan. 1, 2019. The data would include energy data submitted to the agency as part of utilities’ integrated resource plans, descriptions of grid needs or deficiencies, and electricity pricing data. It requires each retail seller of electricity and publicly owned utility to track energy usage for each building in their service territories.
But representatives from California utilities said the bill would provide specific device and setting information that would allow bad actors to physically attack infrastructure. Other disclosed information has the potential to enable people to disable devices on the grid, said John Baranowski, electric distribution planning manager for San Diego Gas & Electric.
“The most concerning aspects of this bill are the implications for grid and cybersecurity,” Baranowski said. The utility supplies military bases and the Port of San Diego, “and all of these customers could be exposed to potential risk” if the data are published, he said, especially the more precise data on customer load and physical system information. He added that the bill duplicates other PUC efforts, and that there is already plenty of data available on potential DER installations.
Representatives from Pacific Gas and Electric and Southern California Edison also opposed the bill, expressing concern about physical security of infrastructure. The bill would also increase information technology costs to be passed on to ratepayers.
Assembly member Brian Dahle (R) suggested that third-party data companies are pushing the proposal so they can obtain information that energy companies collect about their customers.
“If you were that third party, you could then target their customers, and that is what I see this doing,” Dahle said. He questioned the need for the bill given existing programs.
Skinner said it is currently an onerous process for building owners to get certain electricity data and know whether to invest in energy control or efficiency. The bill streamlines the process for tenants to get data to building owners, and ratepayer advocates could also use the data to benefit consumers, she said.
The committee passed the bill on a 9-4 vote, with Dahle and Autumn Burke (D) abstaining. Committee Chairman Chris Holden (D) voted in favor, saying the amended bill put adequate customer protections in place.
A New York judge ruled last week that the state’s Public Service Commission has “the very broadest of powers” to regulate energy service companies and utility rates, especially when seeking to prevent the overcharging of low-income customers.
The June 30 decision by Supreme Court Justice Henry Zwack dismissed a case filed against the commission by the National Energy Marketers Association and three energy service companies (ESCOs), as well as a similar suit by the Retail Energy Supply Association.
Nikola Tesla corner in New York City
The ruling also lifted Zwack’s own temporary injunction against the PSC’s February 2016 “reset order,” which sought to overhaul the business practices of retail energy suppliers and limit the ability of independent energy marketers to sell electricity and gas to low-income customers (15-M-0127, et al.). (See New York ESCO Order Vacated by Court.)
The commission’s order mandated that ESCOs guarantee all mass-market customers an electric rate lower than what their host utility offers, with the exception of “green” offerings, which must include a minimum of 30% renewable energy. The PSC said it intended to combat deceptive practices and boost consumer confidence.
The energy companies argued that the commission overstepped its regulatory authority and violated the privacy of participants in New York’s Home Energy Assistance Program (HEAP).
The injunction did not affect the PSC’s July 2016 moratorium on ESCOs signing up additional low-income customers, which the commission issued after the failure of a collaborative effort to develop a formula that could guarantee savings. (See NYPSC Declares Moratorium on Low-Income Sign-ups.)
No ‘Independent Rights’ for ESCOs
The notion that ESCOs “have somehow morphed into a separate energy sector with independent rights simply has no basis in law,” Zwack wrote in his opinion. “To the extent that ESCOs believe that their regulation must be minimized because of this also has no basis in law.”
The PSC moved quickly last year to address the judge’s concerns about its procedural practices, and last December it launched hearings to examine ESCO marketing practices.
‘Immediate Reform’ Needed
In weighing the privacy of low-income customers against ensuring their right not to overpay for energy services — and against the public’s right not to subsidize ESCOs — the court found the sharing of customers’ HEAP status to be “well within the authority” of the commission.
“What can also be reasonably concluded is that the ESCOs have instead focused on litigation to frustrate the plain purpose of … consumer protection through the adoption of reasonable rates, particularly for those whose utility costs are being subsidized by the public,” the court said. “The ESCO market is in need of immediate reform to protect low-income consumers and to avoid the diminution of taxpayer-funded assistance funds.”
Richard Berkley, director of consumer advocacy group Public Utility Law Project of New York, told RTO Insider that ESCO customers are being overcharged millions of dollars a month, “which pays for a lot of lawyering.”
| EIA
The PSC found that ESCOs overcharged customers by $819 million between January 2014 and June 2016, with low-income customers representing $96 million of the overcharges.
A United Way study in 2016 found that, while federal poverty benchmarks show 15% of New York households experience financial hardship, an additional 29% (2.1 million households) have income above the federal poverty level but still cannot sustain a basic household budget that covers housing, child care, food, transportation and health care.
Warren Buffett is stepping in where two other suitors have failed and will soon make a deal for Oncor, Texas’ largest transmission and distribution utility, according to The Wall Street Journal.
Citing sources “familiar with the matter,” the Journalreported that an announcement by Berkshire Hathaway Energy proposing to acquire Oncor was imminent. The acquisition’s terms have not been disclosed but are thought to be more than $17.5 billion and less than the $18.7 billion NextEra Energy put up last year, according to reports.
Buffett
NextEra’s bid was spiked by the Public Utility Commission of Texas, which ruled in April that the proposed merger was not in the public interest. The commission subsequently rejected two requests for rehearing by NextEra and Oncor. (See NextEra-Oncor Deal Meets Third Denial.)
NextEra’s failure was preceded by that of Dallas-based Hunt Consolidated, which saw its bid fall apart last year when the PUC placed conditions on the transaction that the Hunt family was unable to meet. Hunt’s motion for rehearing also was turned down by the commission. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)
Oncor’s sale is instrumental to resolving the $42 billion bankruptcy of Energy Future Holdings, Oncor’s parent company. EFH declared Chapter 11 bankruptcy in April 2014, and creditors last year reached a settlement contingent on Oncor’s sale.
A regulated utility, Oncor has maintained its profitability despite EFH’s woes. The Berkshire Hathaway acquisition, like the previous two failed bids, would require PUC approval.
Berkshire Hathaway, headed by billionaire Buffett, was among those thought to be interested in the company after the Hunt deal fell apart.
Oncor would join BHE’s NV Energy, MidAmerican Energy and PacifiCorp, which collectively serve 11.6 million electric customers. As of 2016, the company held $85 billion in assets, including almost 236,000 miles of transmission and ownership or control of more than 35 GW of generating capacity. The companies employ about 21,000.
Buffett has made several large purchases lately, including spending $32 billion for Precision Castparts Corp. last year, according to the Journal. With more than $95 billion in cash and cash equivalents, he told investors during Berkshire’s annual meeting in May, the time may come when the company has more cash than it can profitably use.
Warren Buffett’s bid for Oncor won an immediate endorsement from the head of the Texas Public Utility Commission’s staff Friday, suggesting the Oracle of Omaha may succeed where two other suitors for the state’s largest transmission and distribution utility failed. But first, Buffett may have to overcome a challenge from hedge fund Elliott Management, which is reportedly unhappy with the offering price.
Des Moines, Iowa-based Berkshire Hathaway Energy (BHE) announced Friday it had reached an agreement on an all-cash deal that will pay $9 billion for bankrupt Energy Future Holdings (EFH), Oncor’s parent. BHE said that is based on an equity value of $11.25 billion for 100% of Oncor. The Wall Street Journal, which reported Thursday that the deal was imminent, said the purchase has an enterprise value of about $18 billion including debt.
BHE said it expects the purchase to close in the fourth quarter, following approvals by federal and state regulators and the judge overseeing EFH’s bankruptcy.
The PUC rejected prior bids for Oncor by Florida-based NextEra Energy and Dallas-based Hunt Consolidated. But PUC Executive Director Brian Lloyd issued a statement praising the BHE offer, saying he looks “forward to an expeditious filing of this agreement for the commissioners to consider.”
“I applaud both Berkshire Hathaway Energy and Oncor for their productive efforts with PUC staff, the Office of Public Utility Counsel, the Steering Committee of Oncor Cities and Texas Industrial Energy Consumers,” he said. “These parties have developed a transaction that fortifies the successful ring-fence protections the commission ordered in 2007. Both BHE and Oncor are proposing additional assurances regarding Oncor’s independence, financial integrity and commitments to invest in infrastructure, cybersecurity and system reliability for the more than 10 million Texans served by Oncor.”
PUC spokesman Terry Hadley said Lloyd’s statement was based on meetings that preceded the merger announcement. “As is typical with this process, the PUC staff and other parties mentioned in the statement met informally to see what can be resolved prior to an official filing,” Hadley said. He said the first filings on the deal will likely be with the bankruptcy court.
Winning the Debtors
Winning regulators’ approval is only part of the challenge facing Berkshire, however.
Elliott Management, a $33 billion hedge fund that is the biggest holder of EFH bonds, is signaling it may make a competing bid for Oncor, the Journal and Reuters reported late Friday. Elliott added to its stake in the last several months, acquiring them from other funds tired of waiting for an Oncor sale.
Although the fund has no experience in an acquisition of this size, the Journalreported, it could threaten a higher bid to force Berkshire to improve its offer, which is insufficient to pay creditors 100 cents on the dollar. With a “blocking” position in two classes of EFH debt, Elliot has a pivotal role in whether creditors accept the Berkshire offer and complete EFH’s bankruptcy reorganization. Elliott had previously opposed NextEra’s higher bid for Oncor.
Reuters noted that Elliott filed a lawsuit in May asking EFH to consider a debt reorganization that could convert the hedge fund’s debt to equity, which could give it control of Oncor. EFH owns 80% of Oncor.
Prior Deals Rejected
The PUC rejected NextEra’s $18.7 billion bid for Oncor in April, ruling that the proposed merger was not in the public interest. (See NextEra-Oncor Deal Meets Third Denial.)
The commission said it believed the risks posed by NextEra’s acquisition outweighed the benefits, fearing that it would dilute Oncor’s credit profile and eliminate local control. The PUC insisted on strong ring-fencing provisions, including “a truly independent” Oncor board with control over decisions on capital expenditures and operating expenses — a requirement NextEra rejected as a “deal-killer.”
The DallasMorning News reported that BHE has agreed to 44 commitments to the PUC, including an independent board that would have complete control over how to use Oncor’s dividends. Only two of the 12 board members would be appointed by BHE, the paper said.
BHE says that it does not pay dividends “and can invest our profits back into our businesses to provide additional value for our customers. This relationship to our parent uniquely positions us to take a long-term view and to take on ambitious energy projects that other companies may not be able to afford.”
The company also reportedly committed to returning 90% of interest rate savings to customers in rate cuts until the next rate case after one currently pending is final. There would also be no involuntary layoffs or wage and benefit cuts for at least two years for Oncor’s 3,700 workers, the Morning News said.
“The bankruptcy court has to bless it, and it ultimately has to come to commission,” Geoffrey Gay, who represents the Oncor cities steering committee, told the paper. “If they follow the path of failures by Hunt and NextEra, they ought to be able to safely navigate through these obstacles.”
BHE contributed almost 10% of the earnings last year to Buffett’s Berkshire Hathaway conglomerate, whose holdings include GEICO, Kraft Heinz, Fruit of the Loom, Benjamin Moore and BNSF Railway. The company earned $24.07 billion last year, and its $223.6 billion in revenue last year ranked it No. 2 on the Fortune 500 list, behind only Walmart.
Texas Connections
In an apparent bid to curry favor with state regulators, the second paragraph of the press release announcing the deal noted the conglomerate’s other holdings with headquarters in Texas, listing 10 of them.
“Oncor is an excellent fit for Berkshire Hathaway, and we are pleased to make another long-term investment in Texas — when we invest in Texas, we invest big!” Buffett said in a statement. “Oncor is a great company with similar values and outstanding assets.”
| Buffett
Oncor CEO Bob Shapard said the merger would give his company “access to additional operational and financial resources as we continue to position Oncor to support the evolving energy needs of our state.”
“Being part of Berkshire Hathaway Energy is a great outcome for Oncor,” he added in a statement. “Oncor will remain a locally managed Texas company headquartered in Dallas, committed to the communities we serve, and our customers will continue to receive the safe and reliable service they have come to expect from our dedicated team of employees.”
Shapard, who announced plans to retire last October, will become executive chairman of the Oncor board. Senior Vice President and General Counsel Allen Nye will replace him as CEO, as previously announced, Oncor said.
Nye said he was “excited to begin the regulatory approval process,” adding “this transaction has significant support across our key stakeholders.”
Resolving Bankruptcy
Oncor has been ring-fenced since 2007, when EFH, a collaboration of several private-equity firms, acquired TXU Corp. in a leveraged buyout. EFH, saddled by nearly $50 billion in debt when it bet wrong on high gas prices, declared Chapter 11 bankruptcy in 2014.
Creditors last year reached a settlement of the bankruptcy contingent on Oncor’s sale. EFH has already spun off generator Luminant and retailer TXU Energy into a new publicly traded company, Vistra Energy. (See TXU Energy, Luminant Rebrand as Vistra Energy.)
With about 121,000 miles of transmission and distribution, Oncor owns and operates the grid for most of North Texas.
It would join BHE’s NV Energy, MidAmerican Energy and PacifiCorp, which collectively serve 11.6 million electric customers. As of 2016, BHE held $85 billion in assets, including almost 236,000 miles of transmission and ownership or control of more than 35 GW of generating capacity. The companies employ about 21,000.
| Berkshire Hathaway Energy
BHE earned $2.29 billion last year, 9.5% of the conglomerate’s total. Had Oncor’s $431 million in profits been part of BHE in 2016, the energy unit would have generated 11.1% of the conglomerate’s earnings.
BHE is headed by CEO Greg Abel, who has been mentioned as a possible successor to the 86-year-old Buffett as chairman of Berkshire.
The Oncor purchase would be Berkshire’s largest acquisition since its $32 billion deal for Precision Castparts Corp. last year, according to the Journal. With more than $95 billion in cash and cash equivalents, Buffett told investors during Berkshire’s annual meeting in May, the time may come when the company has more cash than it can profitably use.
“Even at $9 billion, the takeover of Oncor … is tens of billions of dollars shy of the mega-deal Berkshire Hathaway Inc. shareholders have anticipated for more than a year,” Tara Lachapelle and Liam Denning wrote in a Bloomberg Gadfly column Friday. “Costco Wholesale Corp., 3M Co. and Hershey Co. are closer to the kinds of names investors had in mind for Berkshire’s next big transaction, as its cash pile grows uncomfortably high.”
MISO’s Independent Market Monitor still sees room for significant improvement after giving the RTO’s markets a passing grade for last year.
“Although the energy markets generally set efficient prices in 2016, we recommend improvements to MISO’s price formation through improved shortage pricing and price-setting by peaking resources,” Monitor David Patton said in his annual State of the Market report released last week, which included nine new recommendations.
The Monitor concluded that — based on the “output gap” measure of economic withholding (the difference between potential and actual energy output) — “potential” withholding of generation represented just 0.11% of load and scarcity mitigation was “infrequently implied.”
The report also showed that modest declines in fuel prices contributed to slightly lower energy prices, make-whole payments and congestion costs than in 2015. MISO’s peak load of 121 GW was slightly higher than the previous year but well below the forecasted peak of 125.9 GW because of mild weather and lower loads. Real-time congestion, however, rose 4.3% from 2015, totaling about $1.4 billion, “amongst the highest in the U.S.,” according to Patton, which he in part attributed to high outage rates in MISO South.
| Potomac Economics
The Monitor’s new market recommendations — many of them already familiar to MISO staff and stakeholders — join a rolling list of unimplemented recommendations dating back to 2010:
Improve shortage pricing by adopting an improved contingency reserve demand curve that reflects the expected value of lost load (VoLL). Patton recommended earlier this year that the RTO immediately up its $3,500/MWh VoLL limit to $9,000/MWh and change its operating reserve demand curve calculation to a sloped curve that he contends would better price shortages. (See MISO, IMM Differ over Scarcity Pricing Changes.)
Transfer control of market-to-market flowgates to improve procedures for M2M activation and coordination. The Monitor would like to see MISO, PJM and SPP become more active in transferring monitoring of constraints when the non-monitoring RTO has all of the transmission loading relief on a flowgate. Last month, MISO and SPP announced plans to begin swapping flowgate control. (See MISO Interregional Plans with SPP Echo PJM Efforts.)
File changes with FERC to give MISO increased authority to approve generation and transmission planned outages and the ability to coordinate outage schedules in order to lower costs. The Monitor said the move would reduce both outage-related congestion during peak outage season and capacity-related emergency events during the shoulder months. Currently, the RTO can only recommend outage schedules and work with operators to reschedule planned outages when reliability is at risk. Last month, both MISO and the Monitor expressed concern over higher-than-usual planned outages in MISO South during the spring. (See MISO South Outages Worry RTO, Monitor.) The Monitor reported that from January 2016 to May 2017, 25% of all real-time congestion ($457 million) could be traced to concurrent generation outages.
Establish regional reserve requirements, creating a local, 30-minute reserve product and developing procurement requirements in areas with voltage and local reliability needs. The Monitor said the reserve product will align the market with reliability needs, allow MISO to accurately price subregional shortages and “lower costs by allowing the markets to satisfy MISO’s reliability needs and reducing out-of-market actions by MISO operators.” Like several other 2016 State of the Market recommendations, this recommendation appeared earlier this year when the Monitor submitted it for consideration in the RTO’s Market Roadmap list of market changes. (See MISO Steering Committee OKs IMM Proposals for Market Roadmap.)
Change MISO’s Day-Ahead Margin Assistance Payment (DAMAP) and Real-Time Offer Revenue Sufficiency Guarantee Payment (RTORSGP) rules to compensate wind operators whose output more closely matches their day-ahead forecasts and reduce gaming opportunities and unjustified costs. Patton warned the RTO late last year that wind generators appeared to be deliberately over-forecasting their output to inflate payments made through revenue sufficiency guarantees. (See MISO IMM Sees Deliberate Over-Forecasting by Wind Operators.)
Increase the accuracy of MISO’s Look-Ahead Commitment recommendation, which was developed in 2012, and seek to improve resource commitment by modeling system conditions for a three-hour future time frame.
Improve forecasting incentives for wind resources by creating a method to validate wind supplier forecasts and use the results to alter dispatch instructions if needed, while improving forecasting incentives by modifying deviation thresholds and settlement rules.
Disqualify from the Planning Resource Auction any resources expected to be unavailable during peak conditions. MISO is currently shopping its own proposal to prohibit resources on extended outages from participating in future auctions or making changes to capture the risk of such outages in loss-of-load-expectation analyses. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)
The Monitor also warned that the $1.50/MW-day footprint-wide clearing price in MISO’s spring capacity auction was too low to be sustainable.
“This is essentially zero. This is not an efficient price under current capacity levels and will motivate poor retirement and export decisions by MISO’s competitive suppliers,” Patton said.
Despite FERC’s rejection of a three-year forward market design for MISO’s retail-choice areas, the RTO should pursue “more reasonable and efficient alternatives,” he added.
In a decision that could boost prospects for controversial state policies favoring select types of electricity generation, the Second Circuit Court of Appeals last week rejected a suit claiming that a Connecticut renewable energy procurement law intruded on FERC’s authority.
A wind turbine installation on I-95 in Fair Haven, CT.
The June 28 ruling affirmed a lower court decision in favor of a Connecticut law that requires the state to solicit proposals for renewable energy projects and utilities to enter into bilateral contracts with the winners. Renewable energy developer Allco Finance challenged the law’s implementation as discriminatory (16-2946, 16-2949).
The court also lifted an injunction it issued last November that blocked the awarding of clean energy contracts by Connecticut, Massachusetts and Rhode Island. (See Court Halts New England Clean Energy Contracts.)
The court’s opinion — which reviewed the Connecticut program based on the Supreme Court’s 2016 decision in Hughes vs. Talen — could influence district courts that are considering motions related to New York and Illinois policies providing zero-emission credits (ZECs) to nuclear plants. (See Federal Suit Challenges NY Nuclear Subsidies.)
FERC Authority
Hughes vs. Talen found that a Maryland plan to spur construction of new natural gas-fired generation encroached on FERC’s authority over wholesale prices under the Federal Power Act. But the Second Circuit ruling identified a key distinction between the Maryland and Connecticut programs.
“While Maryland sought essentially to override the terms set by the FERC-approved PJM auction, and required transfer of ownership through the FERC-approved auction, Connecticut’s program does not condition capacity transfers on any such auction,” the appeals court said. “Connecticut, instead, transfers ownership of electricity from one party to another by contract, independent of the auction.”
Furthermore, the contracts stemming from the requests for proposals are just the kind of bilateral agreements already subject to FERC oversight, the court said.
And while the appeals court affirmed that “states may not regulate interstate wholesale sales of electricity unless Congress creates an exception to the FPA,” it also determined that the Public Utility Regulatory Policies Act “contains such an exception, permitting states to foster electric generation by certain power production facilities … that have no more than 80 MW of capacity and use renewable generation technology.”
“The decision comes out on the right side legally, clearly on the better side for the states who want to set up programs to encourage renewable energy,” said Seth Jaffe of the law firm Foley Hoag, who wrote a blog post on the case. “The court properly noted that the state really wasn’t getting in the way of FERC setting wholesale prices.”
In a June 30 blog post, John Moore of the Natural Resources Defense Council wrote that “contrary to the claims of some generators who would like to see state energy laws invalidated per Hughes, the 2nd Circuit made clear that Hughes applies only to a narrow class of state schemes that, like Maryland’s, seek to ‘override’ the rate set by the FERC-approved auction and instead guarantee a generator a wholly different rate — not policies like the Connecticut clean energy programs.”
Dormant Commerce Clause Claims Rejected
The Second Circuit also rejected Allco’s claims that Connecticut violated the dormant Commerce Clause of the U.S. Constitution: the idea that states may not pass laws discriminating against interstate commerce to protect intrastate commerce. Allco argued Connecticut’s law violated the clause by making the state’s acceptance of renewable energy credits (RECs) contingent on the ability of a generator to deliver its electricity to the New England grid.
SunPower “Intelegant” award-winning installation in Westport, CT.
Allco claimed that Connecticut’s rules discriminated against the company’s solar facility in Georgia by not letting its RECs count toward Connecticut utilities’ renewable portfolio standard requirements. The company also argued that Connecticut discriminated against Allco’s New York facility in requiring producers of RECs in adjacent control areas to pay transmission fees in order to sell their credits to Connecticut utilities.
The Second Circuit first considered “whether the allegedly competing entities — Allco’s Georgia generator, on the one hand, and generators located in ISO-NE and adjacent control areas, on the other — provide different products, i.e., different RECs. We find that they do.” (See NYISO Sees Carbon Adder as Way to Link ZECs to Markets.)
The opinion gave “greater weight” to the market for RECs produced by generators able to connect to Connecticut’s grid and noted that “Connecticut’s RPS program makes geographic distinctions between RECs only insofar as it piggybacks on top of geographic lines drawn by ISO-NE and the [New England Power Pool], both of which are supervised by FERC — not the state of Connecticut.”
Regarding the court’s dormant Commerce Clause finding, Jaffe said, “I think they got it right; the reasoning is pretty sound, but I can certainly imagine people continuing to litigate this.”
The decision said it recognized “the importance of Connecticut’s interest in protecting the market for RECs produced within the ISO-NE or in adjacent areas. Connecticut’s RPS program serves its legitimate interest in promoting increased production of renewable power generation in the region.”
The court’s arguments in favor of the Connecticut program “are not that different from arguments that we’ve sometimes seen rejected by the courts, in saying, ‘Well, we understand the policy preference, but you’re not allowed to essentially discriminate,’” Jaffe said.
[Editor’s Note: An earlier version of this story said the ruling was by the D.C. Circuit Court of Appeals.]
DENVER — SPP and Peak Reliability extolled their virtues as reliability coordinators (RCs) before the Colorado Public Utilities Commission last week in a bid to provide the reliability function for the Mountain West Transmission Group.
Peak Reliability is Mountain West’s current RC. SPP would include the RC function among the bundled services it would provide Mountain West, should the informal collaboration of Western utilities eventually become members of the RTO. (See Mountain West, SPP Tout RTO Membership to Colo. PUC.)
The courtship is leaving the Colorado PUC a little queasy.
“This is like if your child potentially dates, if not marries, the wrong person,” Chairman Jeff Ackermann said in wrapping up the information session. “Take that wherever you want to go, but ultimately, consenting adults do what consenting adults want to do.”
“We may not want to pay for the wedding,” Commissioner Frances Koncilja pointed out.
Mountain West — comprising eight investor-owned utilities, municipalities, generation and transmission cooperatives, federal power marketing administration projects, and their subsidiaries — announced in January that it was beginning discussions with SPP about potentially joining the RTO. The group expects to arrive at a decision by October.
| WAPA
However, Koncilja prodded a panel of Mountain West representatives as to when the commission would see financial numbers coming out of the negotiations with SPP.
“I share your sense of urgency,” said Steve Beuning, director of market operations for Mountain West member Xcel Energy, offering no further response.
Peak Reliability currently provides only RC services to Mountain West for about 5 cents an hour, CEO Marie Jordan said.
If SPP is to assume RC responsibilities for Mountain West, its members “would continue to pay what they pay Peak now,” according to SPP COO Carl Monroe.
“What they save is anything they would have to do if we were not the RC,” Monroe said, reminding the commission that SPP would also likely be running the balancing authority and the markets, besides other functions. “I know when we have to provide the functions we provide, we can do it more cost-effectively and more reliably than if we [were just the RC].”
Monroe said SPP’s “first line of defense” against reliability concerns is to let the market take action by resolving binding constraints through economic dispatch, which uses the lowest-cost generation facilities to meet consumer demand while recognizing any operational limits.
“The market itself provides you that mechanism. The market, for us, is a tool to maintain enhanced reliability,” he said.
Beuning pointed out that economic dispatch is “the missing piece in our tool kit.” The Western Electricity Coordinating Council, which has served as the Western Interconnection’s Regional Entity since 2007, has yet to implement economic dispatch. Peak was spun off as an independent RC from the WECC in 2014.
Economic dispatch “is the one thing that comes along with being a market operator,” Beuning said. “It’s my belief and opinion that at this point, we could obtain an integrated service at a lower cost for our customers, instead of paying for RC services or paying the Peak.”
“It would be a lost opportunity cost for us to not bundle those services together,” said Denton McGregor, reliability center manager for Mountain West member Black Hills Power.
Status Quo — or No
Jordan touted Peak’s experience as Mountain West’s incumbent RC and the knowledge it has gained providing the same service for the Western Interconnection. She said Peak continuing as the region’s single RC would address reliability concerns caused by the continued addition of renewable and intermittent resources, and it would provide a “single, unbiased” entity focused exclusively on reliability coordination.
“A single RC has been a very important piece of the vision for reliability in the West,” Jordan said. “The biggest concern is how the interconnection continues to bring on [renewables]. I also don’t want to underestimate how knowledge grows … we’re mature in our tools, we’re mature in our sophistication and we have learned. Based on feedback I get from our funding members, our model is becoming so much more reliable for them, from the time we started … to where we are today. It’s been tremendous growth.”
A nonprofit organization like SPP, Peak is responsible for an area of 1.6 million square miles that includes all or parts of 14 western states, Canada’s British Columbia and the northern portion of Baja California, Mexico. It oversees more than 110,000 miles of transmission lines, with centers in Vancouver, Wash., and Loveland, Colo.
For his part, Monroe played up SPP’s experience as both an RC and a market operator, underscoring the understanding the RTO gained integrating RC services in the Western Interconnection with the 2015 addition of the Integrated System. (See Integrated System to Join SPP Market Oct. 1.)
“Reliability for us is job [No.] 1,” he said. “When we’ve added things, we’ve done so in a manner that protects reliability or enhances reliability. Part of the benefits Mountain West is looking to get are those benefits at a cheaper cost to the consumers themselves. Everything we do is designed to enhance reliability at a cheaper cost.”
WECC CEO Jim Robb said costs would likely increase for Mountain West members should SPP become their RC.
“The cost of providing RC services isn’t particularly scalable,” he said. “I can’t see Peak’s cost structure changed, but it seems to me the pressures in aggregate go up. How they are allocated among customers remains to be seen.”
And that’s an issue for the Colorado PUC.
“We’re concerned about how these costs roll out and which ones end up back here in this room at some point in the future,” Ackermann said.
Monroe said SPP would incur additional costs should it separate the RC function from the market and balancing authority functions. He said there is a benefit to having multiple RCs in an interconnection, as evidenced by the 13 RCs in the Eastern Interconnection.
“We think [multiple RCs] reduces risk because now you have two different organizations and two different systems looking over that whole area,” he said. “In the East, we reduce the risk because we have people helping us do that. We’ve never been in an environment where we weren’t coordinating with other parties.”
Negative Consequences
Losing Mountain West would cost Peak — which has operated with a $44.6 million budget for each of the last two years — about 10% of its load.
“It’s negative to the interconnection, [and] it’s negative to area reliability — and not just for the Mountain West,” Jordan told RTO Insider. “We’ve taken full responsibility to keep this grid functioning reliably, and that’s a consensus shared by our members.”
The PUC has tentatively scheduled a third information session on Mountain West’s proposal to join SPP. The Aug. 24 session will focus on governance issues.
SPP will be holding its leadership meetings at the Colorado Convention Center and a nearby hotel in Denver next month. As he did during the PUC’s first information session in March, Monroe invited those in the room to attend the meetings and see how the RTO governs itself. He said SPP set aside 190 seats for the July 11-12 Markets and Operations Policy Committee meeting, with 170 attendees having already registered.
