VALLEY FORGE, Pa. — Progress in PJM’s special session of the Market Implementation Committee on distributed energy resources has reached a point where details matter.
Stakeholders spent much of the group’s meeting on Friday clarifying definitions, debating whether certain terms should be used and delineating what is in and out of the group’s scope.
“Just because something’s not in the Tariff doesn’t mean it’s not a defined term used in the business and a good utility practice,” Calpine’s David “Scarp” Scarpignato said. “Some of these are recognized terms from an engineer’s standpoint.”
Among the questions is whether the aggregation rules will focus on grouping small projects to reach the 100-kW minimum for participating in PJM markets or expand to cover grouping multiple larger projects that are at the same site.
“In my mind, we were talking about aggregation mostly to meet that market threshold,” said Drew Adams of A.F. Mensah. “It sounds like the aggregation discussion has expanded a little bit beyond that.”
During the discussion, stakeholders largely agreed that electric distribution companies should retain a substantial amount of control over project approval, such as defining the size, location and type of aggregation projects they will accept.
John Farber of the Delaware Public Service Commission said the group should also decide rules on whether projects can cross distribution service territories. He said it will be important to consider how electric vehicles are handled because definitions that are too restrictive could inhibit their development.
“I’m not sure how these resources are going to develop, but I’m hesitant to develop rules that are too restrictive,” Farber said.
PJM staff also presented an informal poll to determine stakeholder interests in how DER is incorporated into ancillary services markets. PJM’s Andrew Levitt said one consideration will be how much visibility the RTO should have into resources that operate behind a load. When it sells into the wholesale markets, PJM will be able to monitor its performance. However, when it is simply reducing the owner’s load, the current rules don’t provide the same information.
Levitt presented a proposed rule to require submetering of DERs at the resource before it’s tied to the load.
“This is the most substantial change in the whole proposal,” Levitt said. “Your performance of ancillary services would be measured at the DER rather than measured at the point of interconnection, as it would be under the status quo.”
The group has no meetings planned until August, when it will meet three times.
The most significant innovation in FERC Order 1000? Transmission competition.
Where and when transmission competition is properly implemented, it is a staggering success. Consider a recent PJM “window” seeking solutions to reliability and congestion needs.
One such need was relief of high congestion on a transmission corridor between Pennsylvania and Maryland where low-cost natural gas generation from Pennsylvania hits a bottleneck. PJM received 44 proposals from nine separate entities, proposing solutions ranging in cost from $6 million to $192 million.[1]
Before transmission competition, it was like the color of a Model T. You could have any solution you wanted as long as it was the transmission owner’s solution.[2]
And TOs never have had an incentive to find the most cost-effective solution, for reasons brilliantly explained by Montana Public Service Commissioner Travis Kavulla in his recent American Affairs article:[3]
This so-called cost-of-service regulation suggests to the utility that it should spend as much as possible, even when less might do. The barometer for whether an investment is wise for a utility is not capital productivity, but whether expenditures will be disallowed by the regulator. This seldom occurs. Indeed, the legal presumption that governs the arcane, trial-like proceedings of utility commissions is that all utility spending is prudent. A utility earns a return even on the cost of decorating the C-suite.
Investment funds understand this dynamic perfectly. Their analysis often simply celebrates more and more capital investment (“ratebase” or “capex” in industry lingo), with little attention to the underlying value it delivers to customers. One recent investor note by UBS on the New Jersey utility PSEG was titled “More Ratebase Please.”
The other good news about the advent of transmission competition is how little it costs to implement. Last year it cost PJM $451,610 to administer its Order 1000 proposal windows; project sponsors paid proposal fees of $490,000.[4] So PJM stakeholders made money implementing competition.[5]
The bad news is that there is very little of this good thing. The scope of transmission competition has become severely restricted. If you look at the pie chart below, only the palest blue slice — less than 10% of the cost of transmission projects in PJM in 2016 — had competition.[6]
The exceptions to transmission competition have swallowed more than 90% of the rule.[7] The biggest exception — $899 million in PJM last year — is “Supplemental” projects, which by definition are projects that PJM itself does not consider needed. The TOs have the unilateral right to build whatever they’d like, as long as they tell PJM what they are doing.
Under this exception, billions of dollars are being spent based on TO claims of “aging infrastructure,” but no one knows if those billions materially improve reliability. Indeed, a Lawrence Berkeley National Laboratory study found no statistical correlation between transmission (and distribution) spending and reliability.[8]
Obviously, at some age transmission lines would fall down and affect reliability, but there are few instances of that happening. There are many causes of outages (severe weather, lightning, human error, misoperations, and even metallic balloons and squirrels).[9]
This enormous transmission spending beyond PJM’s purview reverses the situation from 10 years ago when the vast bulk of transmission spending in the RTO was what it determined was needed.[10]
The TO exclusives seem to be falling into a regulatory gap, as states seem to assume that PJM is reviewing all this. But PJM only has oversight over Order 1000 projects and “Immediate Need” projects, and only uses competitive windows for the former.
And, unbelievable as it may seem, PJM seems to be the best of the RTOs.
In ISO-NE, “Immediate Need” and other exceptions appear to have swallowed the rule entirely.[11] The section of the ISO-NE webpage listing competitive transmission RFPs is … empty.[12]
In MISO, the allocation of transmission costs was changed so that virtually all transmission projects qualify for the “local” exception. How many projects have been subject to competition? That loneliest number: One.
States (and others) are increasingly concerned about the explosion in transmission costs,[13] but one simple step states could take on their own is to require, as a condition of the state certificate and/or rate recovery process, that all projects costing more than some threshold be subject to an Order 1000 window. FERC could do the same as a condition of cost flow through in FERC-jurisdictional transmission rates. This would not solve the problem of unwarranted projects, but it would help mitigate the carte blanche in spending on such projects.[14]
Bottom line: Transmission competition works great when properly implemented. But it’s been severely limited. We need more of the good thing.
Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.
By the way, there is a right way and a wrong way to implement transmission competition. PJM identifies transmission “needs” and requests proposals to address these needs (the “sponsorship model”). As a result, PJM gets wide-ranging, solution-based proposals (in the example I gave, projects ranging from $6 million to $192 million). In contrast, CAISO identifies specific projects and requests proposals to build those specific projects (the “procurement model”). Thus, CAISO totally misses the opportunity for competitors to offer solutions that may cost a fraction of what the ISO thinks best. ↑
This renders inexplicable an RTO claim that transmission competition is not worthwhile because of “staff headaches.” (See PJM, SPP Chiefs Share Frustration with Order 1000.) When potential savings are in the billions, and the cost of implementation is in the hundreds of thousands, the benefit-to-cost value proposition — at least for customers — is self-evident. ↑
It should be noted that going forward, the exceptions are expanding with the exclusion of facilities below 200 kV and of upgrades to substation equipment (except transformers). So the less than 10% of transmission spend subject to competition will get even smaller. ↑
SACRAMENTO — As CEO of the Independent Energy Producers Association (IEPA), Jan Smutny-Jones has had a front-row seat in the California energy debate since 1987. IEPA represents independent energy producers including biomass, geothermal, small hydro, solar, wind, cogeneration and natural gas-fired merchant facilities, with offices just a block from the state capitol.
Smutny-Jones is an advocate for Secure California’s Energy Future, a campaign urging the State Legislature to expand CAISO’s market into other areas of the West. But some members of the State Assembly and market participants want the state to go slow on regionalization, which would require bringing representatives from other states onto the ISO’s Board of Governors. (See California Lawmakers Take Up CAISO Expansion.)
Electricity planning has changed greatly since his youth, when he watched offshore oil tankers supplying the Huntington Beach power plant as he body-surfed. But renewable generation is a decades-old concept in California, as is Western regional market coordination. There has been a lot of public debate about California’s aggressive renewable policies, but environmentally conscious planning has long been a hallmark in the Golden State for decades, Smutny-Jones says.
“Where we are today in terms of the discussion, it actually has a pretty long pedigree,” he said in a recent interview. “It isn’t like we just cooked this up in AB 32 or whatever.” Assembly Bill 32, the Global Warming Solutions Act of 2006, was a landmark law requiring the state to reduce its greenhouse gas emissions to 1990 levels by 2020.
The 2015 Clean Energy and Pollution Reduction Act, which established the state’s 50% by 2030 renewable portfolio standard, also directed the state’s energy agencies to explore transforming CAISO into a regional entity to help meet its clean energy target. More recently, the State Senate approved a bill setting a 100% renewable generation goal by 2045, the latest example of the state’s aggressive approach toward clean energy and climate change. (See California Senate Passes Bill Mandating 100% RPS.) The Assembly Committee on Utilities and Energy is due to review the legislation July 12.
Because the CAISO board is not a policymaking body but follows state policies, some lawmakers and industry stakeholders worry that regionalizing the ISO will dilute the state’s influence on the direction of energy planning, Smutny-Jones said. And other states such as Wyoming and Utah don’t want to be forced to conform to California energy policies if control of their transmission infrastructure is turned over to a regional ISO.
The Sierra Club says that if PacifiCorp’s Utah-based coal generation is brought into CAISO, for example, it will bring coal-fired power into the state, and the environmental group is pressuring the company to retire the assets. But PacificCorp in recent years has instead been investing in the plants.
IEPA Has Represented Solar Power Developers For Decades | Cubit Power Systems
“If we are expecting other states to respect California’s procurement policies, California has to be cognizant of the fact that Utah is not going to start prematurely shutting down coal plants — costing lots of money to its ratepayers — based on trying to expand the ISO,” Smutny-Jones said. Most utilities in the West are moving away from coal-fired power anyhow, so there isn’t much concern that regionalization will bolster coal generation, he said.
Building trade groups and elected officials are concerned about exporting jobs if renewable generation is shifted to other states. But lack of transmission will create a need for California-based generation, he said, and there are other land-use laws that will reduce development of utility-scale renewable generation in Western desert areas.
The list of groups supporting the regionalization plan includes Natural Resources Defense Council, Sierra Business Council, Solar Energy Industries Association, SunPower, Silicon Valley Leadership Group, and Union of Concerned Scientists.
Regionalization could help California’s natural gas-fired plants stay in business and make the market more efficient across the West, he said. The abundance of solar has put pressure on the state’s natural gas plants by changing the operational profile of the grid. In 2008, there was only about 300 MW of utility-scale solar in the state, but that figure has reached almost 10,000 MW as the cost of photovoltaics has come down and the state adopted its RPS. This has changed the operating profile for natural gas plants that are not receiving the price signals to stay in business.
“There are significant challenges in the market right now,” he said, adding that he is concerned that power plant owners will start shutting down plants and affect reliability. This will be a long-term issue that must be dealt with, he said.
Regardless of the state’s policies, a primary attraction for California renewable generation in a regional context is that it is now inexpensive, Smutny-Jones said.
“I don’t think Utah necessarily wants to buy power from California because it’s green and the right thing to do, but they will buy it if it’s cheap.”
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.”
